Generation and Transmission Planning

Section 12 Planning

2015 Quarterly State of the Market Report for PJM: January through September 435© 2015 Monitoring Analytics, LLC

Generation and Transmission PlanningOverviewPlanned Generation and Retirements•Planned Generation. As of September 30, 2015, 79,603.8 MW of

capacity were in generation request queues for construction through 2024, compared to an average installed capacity of 185,656.0 MW as of September 30, 2015. Of the capacity in queues, 6,727.8 MW, or 8.5 percent, are uprates and the rest are new generation. Wind projects account for 14,997.1 MW of nameplate capacity or 18.8 percent of the capacity in the queues. Combined-cycle projects account for 52,950.0 MW of capacity or 66.5 percent of the capacity in the queues.

•Generation Retirements. As shown in Table 12-6, 27,029.0 MW have been, or are planned to be, retired between 2011 and 2020. Of that, 3,264.7 MW are planned to retire after 2015. In the first three quarters of 2015, 9,847.3 MW were retired, of which 7,661.8 MW were coal units. The coal unit retirements were a result of the EPA’s Mercury and Air Toxics Standards (MATS) and low gas prices.

•Generation Mix. A significant shift in the distribution of unit types within the PJM footprint continues as natural gas fired units enter the queue and steam units retire. While only 1,947.0 MW of coal fired steam capacity are currently in the queue, 55,474.28 MW of gas fired capacity are in the queue. The replacement of coal steam units by units burning natural gas could significantly affect future congestion, the role of firm and interruptible gas supply, and natural gas supply infrastructure.

Generation and Transmission Interconnection Planning Process•Any entity that requests interconnection of a new generating facility,

including increases to the capacity of an existing generating unit, or that requests interconnection of a merchant transmission facility, must follow the process defined in the PJM tariff to obtain interconnection

service.1 The process is complex and time consuming at least in part as a result of the required analyses. The cost, time and uncertainty associated with interconnecting to the grid may create barriers to entry for potential entrants.

•The queue contains a substantial number of projects that are not likely to be built. Excluding currently active projects and projects currently under construction, 2,246 projects, representing 264,381.0 MW, have completed the queue process since its inception. Of those, 604 projects, 33,328.5 MW, went into service. Of the projects that entered the queue process, 87.4 percent of the MW withdrew prior to completion. Such projects may create barriers to entry for projects that would otherwise be completed by taking up queue positions, increasing interconnection costs and creating uncertainty.

•Feasibility, impact and facilities studies may be delayed for reasons including disputes with developers, circuit and network issues and retooling as a result of projects being withdrawn.

•Where the transmission owner is a vertically integrated company that also owns generation, there is a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is a competitor to the generation of the parent company. There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of a merchant transmission developer which is a competitor of the transmission owner. There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is part of the same company as the transmission owner.

Regional Transmission Expansion Plan (RTEP)•Artificial Island is an area in southern New Jersey that includes nuclear

units at Salem and at Hope Creek in the PSEG zone. On April 29, 2013, PJM issued a request for proposal (RFP), seeking technical solutions to improve stability issues and operational performance under a range of anticipated system conditions, and the elimination of potential planning

1 See PJM, OATT Parts IV & VI.

2015 Quarterly State of the Market Report for PJM: January through September

436 Section 12 Planning © 2015 Monitoring Analytics, LLC

criteria violations in this area.2 On July 30, 2015, the PJM Board of Managers accepted PJM’s recommendation to assign the project to LS Power, a non-incumbent, PSEG, and PHI with a total cost estimate between $263M and $283M.3,4

•On October 25, 2012, Schedule 12 of the tariff and Schedule 6 of the OA were changed to address FERC Order No. 1000 reforms to the cost allocation requirements for local and regional transmission planning projects that were formerly defined in Order No. 890. The new approach was applied for the first time to the 2013 RTEP. Since then, some developers have raised concern with the cost allocations using the new solution based dfax method.

Backbone Facilities•PJM baseline transmission projects are implemented to resolve reliability

criteria violations. PJM backbone transmission projects are a subset of significant baseline projects, which are intended to resolve multiple reliability criteria violations and congestion issues and which may have substantial impacts on energy and capacity markets. The current backbone projects are Mount Storm-Doubs, Jacks Mountain, Susquehanna-Roseland, and Surry Skiffes Creek 500kV.

Transmission Facility Outages•PJM maintains a list of reportable transmission facilities. When the

reportable transmission facilities need to be taken out of service, PJM transmission owners are required to report planned transmission facility outages as early as possible. PJM processes the transmission facility outage requests according to rules in PJM’s Manual 3 to decide if the outage is on time, late, or past its deadline and whether or not they will allow the outage.5

2 See “Artificial Island Recommendations,” presented at the TEAC meeting on April 28, 2015 at <http://www.pjm.com/~/media/committees-groups/committees/teac/20150428-ai/20150428-artificial-island-recommendations.ashx>

3 See “Artificial Island Recommendations,” presented at the TEAC meeting on April 28, 2015 at <http://www.pjm.com/~/media/committees-groups/committees/teac/20150428-ai/20150428-artificial-island-recommendations.ashx>

4 See letter from Terry Boston concerning the Artificial Island Project at <http://www.pjm.com/~/media/documents/reports/board-statement-on-artificial-island-project.ashx>

5 PJM. “Manual 03: Transmission Operations,” Revision 46 (December 1, 2014), Section 4.

•There were 14,458 transmission outage requests submitted for the first nine months of 2015. Of the requested outages, 79.2 percent were planned for five days or shorter and 5.4 percent were planned for longer than 30 days. Of the requested outages, 49.3 percent were late according to the rules in PJM’s Manual 3.

•There were 14,283 transmission outage requests submitted for the first nine months of 2014. Of the requested outages, 80.4 percent were planned for five days or shorter and 5.3 percent were planned for longer than 30 days. Of the requested outages, 49.6 percent were late according to the rules in PJM’s Manual 3.

RecommendationsThe MMU recommends improvements to the planning process.

•The MMU recommends the creation of a mechanism to permit a direct comparison, or competition, between transmission and generation alternatives, including which alternative is less costly and who bears the risks associated with each alternative. (Priority: Low. First reported 2013. Status: Not adopted.)

•The MMU recommends that rules be implemented to permit competition to provide financing for transmission projects. This competition could reduce the cost of capital for transmission projects and significantly reduce total costs to customers. (Priority: Low. First reported 2013. Status: Not adopted.)

•The MMU recommends that the question of whether Capacity Injection Rights (CIRs) should persist after the retirement of a unit be addressed. Even if the treatment of CIRs remains unchanged, the rules need to ensure that incumbents cannot exploit control of CIRs to block or postpone entry of competitors.6 (Priority: Low. First reported 2013. Status: Not adopted.)

•The MMU recommends outsourcing interconnection studies to an independent party to avoid potential conflicts of interest. Currently, these studies are performed by incumbent transmission owners under

6 See “Comments of the Independent Market Monitor for PJM,” Docket No. ER12-1177-000, <http://www.monitoringanalytics.com/reports/Reports/2012/IMM_Comments_ER12-1177-000_20120312.pdf>.

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PJM’s direction. This creates potential conflicts of interest, particularly when transmission owners are vertically integrated and the owner of transmission also owns generation. (Priority: Low. First reported 2013. Status: Not adopted.)

•The MMU recommends improvements in queue management including that PJM establish a review process to ensure that projects are removed from the queue if they are not viable, as well as a process to allow commercially viable projects to advance in the queue ahead of projects which have failed to make progress, subject to rules to prevent gaming. (Priority: Medium. First reported 2013. Status: Not Adopted.)

•The MMU recommends an analysis of the study phase of PJM’s transmission planning to reduce the need for postponements of study results, to decrease study completion times, and to improve the likelihood that a project at a given phase in the study process will successfully go into service. (Priority: Medium. First reported Q1, 2014. Status: Partially adopted, 2014.)

•The MMU recommends that PJM enhance the transparency and queue management process for merchant transmission investment. Issues related to data access and complete explanations of cost impacts should be addressed. The goal should be to remove barriers to competition from merchant transmission. (Priority: Medium. First reported Q2, 2015. Status: Not adopted.)

•The MMU recommends that PJM establish fair terms of access to rights of way and property, such as at substations, in order to remove any barriers to entry and permit competition between incumbent transmission providers and merchant transmission providers in the RTEP. (Priority: Medium. First reported 2014. Status: Not adopted.)

•The MMU recommends that PJM reevaluate all transmission outage tickets as if they were new requests when an outage is rescheduled and apply the standard rules for late submissions to any such outages. (Priority: Low. First reported 2014. Status: Not adopted.)

•The MMU recommends that PJM have a clear definition of the congestion analysis required for transmission outage requests in Manual 3. (Priority: Low. New recommendation. Status: Not adopted.)

•The MMU recommends that PJM modify the rules to reduce or eliminate the approval of late outage requests submitted after the FTR auction bidding opening date. (Priority: Low. New recommendation. Status: Not adopted.)

ConclusionThe goal of PJM market design should be to enhance competition and to ensure that competition is the driver for all the key elements of PJM markets. But transmission investments have not been fully incorporated into competitive markets. The construction of new transmission facilities has significant impacts on the energy and capacity markets. But when generating units retire or load increases, there is no market mechanism in place that would require direct competition between transmission and generation to meet loads in the affected area. In addition, despite FERC Order No. 1000, there is not yet a transparent, robust and clearly defined mechanism to permit competition to build transmission projects, to ensure that competitors provide a total project cost cap, or to obtain least cost financing through the capital markets.

The addition of a planned transmission project changes the parameters of the capacity auction for the area, changes the amount of capacity needed in the area, changes the capacity market supply and demand fundamentals in the area and may effectively forestall the ability of generation to compete. But there is no mechanism to permit a direct comparison, let alone competition, between transmission and generation alternatives. There is no mechanism to evaluate whether the generation or transmission alternative is less costly, whether there is more risk associated with the generation or transmission alternatives, or who bears the risks associated with each alternative. Creating such a mechanism should be an explicit goal of PJM market design.

The PJM queue evaluation process should be improved to ensure that barriers to competition for new generation investments are not created. Issues that need



to be addressed include the ownership rights to CIRs, whether transmission owners should perform interconnection studies, and improvements in queue management.

The PJM rules for competitive transmission development through the RTEP should build upon FERC Order No. 1000 to create real competition between incumbent transmission providers and merchant transmission providers. PJM should enhance the transparency and queue management process for merchant transmission investment. Issues related to data access and complete explanations of cost impacts should be addressed. The goal should be to remove barriers to competition from merchant transmission. Another element of opening competition would be to consider transmission owners’ ownership of property and rights of way at or around transmission substations. In many cases, the land acquired included property intended to support future expansion of the grid. Incumbents have included the costs of the property in their rate base. Because PJM now has the responsibility for planning the development of the grid under its RTEP process, property bought to facilitate future expansion should be a part of the RTEP process and be made available to all providers on equal terms.

The process for the submission of planned transmission outages needs to be carefully reviewed and redesigned to limit the ability of transmission owners to submit transmission outages that are late for FTR Auction bid submission dates and are late for the Day Ahead Energy Market. The submission of late transmission outages can inappropriately affect market outcomes when market participants do not have the ability to modify market bids and offers.

Planned Generation and RetirementsPlanned Generation AdditionsExpected net revenues provide incentives to build new generation to serve PJM markets. The amount of planned new generation in PJM reflects investors’ perception of the incentives provided by the combination of revenues from the PJM Energy, Capacity and Ancillary Service Markets. On September 30, 2015, 79,603.8 MW of capacity were in generation request queues for construction

through 2024, compared to an average installed capacity of 193,587.7 MW as of September 30, 2015. Although it is clear that not all generation in the queues will be built, PJM has added capacity annually since 2000 (Table 12-1). In the first nine months of 2015, 3,138.9 MW of nameplate capacity went into service in PJM.

Table 12‑1 Year‑to‑year capacity additions from PJM generation queue: Calendar years 2000 through September 30, 2015Year MW2000 505.02001 872.02002 3,841.02003 3,524.02004 1,935.02005 819.02006 471.02007 1,265.02008 2,776.72009 2,515.92010 2,097.42011 5,007.82012 2,669.42013 1,126.82014 2,659.02015 (to date) 3,138.9

PJM Generation QueuesGeneration request queues are groups of proposed projects, including new units, reratings of existing units, capacity resources and energy only resources. Each queue is open for a fixed amount of time. Studies commence on all projects in a given queue when that queue closes. The duration of the queue period has varied. Queues A and B were open for a year. Queues C-T were open for six months. Starting in February 2008, Queues U-Y1 were open for three months. Starting in May 2012, the duration of the queue period was reset to six months, starting with Queue Y2. Queue AB1 is currently open.

All projects that have been entered in a queue have a status assigned. Projects listed as active are undergoing one of the studies (feasibility, system impact,

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facility) required to proceed. Other status options are under construction, suspended, and in-service. Withdrawn projects are removed from the queue and listed separately. A project cannot be suspended until it has reached the status of under construction. Any project that entered the queue before February 1, 2011, can be suspended for up to three years. Projects that entered the queue after February 1, 2011, face an additional restriction in that the suspension period is reduced to one year if they affect any project later in the queue.7 When a project is suspended, PJM extends the scheduled milestones by the duration of the suspension. If, at any time, a milestone is not met, PJM will initiate the termination of the Interconnection Service Agreement (ISA) and the corresponding cancellation costs must be paid by the customer.

Table 12-2 shows MW in queues by expected completion date and MW changes in the queues between June 30, 2015, and September 30, 2015, for ongoing projects, i.e. projects with the status active, under construction or suspended.8 Projects that are already in service are not included here. The total MW in queues increased by 2,142.5 MW, or 2.8 percent, from 77,461.3 MW at the end of the second quarter of 2015. The change was the result of 6,030.3 MW in new projects entering the queue, 2,176.5 MW in existing projects withdrawing, and 1,002.9 MW going into service. The remaining difference is the result of projects adjusting their expected MW.

Table 12‑2 Queue comparison by expected completion year (MW): June 30, 2015 vs. September 30, 20159

Quarterly Change Year As of 6/30/2015 As of 9/30/2015 MW Percent2015 12,632.6 10,378.6 (2,253.9) (17.8%)2016 16,466.5 15,510.3 (956.2) (6.2%)2017 13,821.4 13,349.4 (472.0) (3.5%)2018 14,603.1 14,608.1 5.0 0.0%2019 12,274.8 18,746.8 6,472.0 34.5%2020 4,442.0 3,789.6 (652.4) (17.2%)2021 1,377.0 1,377.0 0.0 0.0%2022 250.0 250.0 0.0 0.0%2024 1,594.0 1,594.0 0.0 0.0%Total 77,461.3 79,603.8 2,142.5 2.8%

7 See PJM. Manual 14C. “Generation and Transmission Interconnection Process,” Revision 8 (December 20, 2012), Section 3.7, <http://www.pjm.com/~/media/documents/manuals/m14c.ashx>.

8 Expected completion dates are entered when the project enters the queue. Actual completion dates are generally different than expected completion dates.

9 Wind and solar capacity in Table 12-2 through Table 12-5 have not been adjusted to reflect derating.

Table 12-3 shows the yearly project status changes in more detail and how scheduled queue capacity has changed between June 30, 2015, and September 30, 2015. For example, 6,030.3 MW entered the queue in the second quarter of 2015, 5,695.6 MW of which are currently active and 100 MW of which were withdrawn before the quarter ended. Of the total 50,091.6 MW marked as active at the beginning of the quarter, 2,023.7 MW were withdrawn, 2,007.3 MW started construction, and 65.5 MW went into service by the end of the third quarter. The Under Construction column shows that 184.0 MW came out of suspension and 2,007.3 MW began construction in the third quarter of 2015, in addition to the 20,953.1 MW of capacity that maintained the status under construction from the previous quarter.

Table 12‑3 Change in project status (MW): June 30, 2015 vs. September 30, 2015

Status at 9/30/2015

Status at 6/30/2015Total at

6/30/2015 Active SuspendedUnder

Construction In Service Withdrawn(Entered in Q3 2015) 5,695.6 0.0 2.0 232.7 100.0 Active 50,091.6 45,460.7 0.0 2,007.3 65.5 2,023.7 Suspended 4,406.3 0.0 4,144.4 184.0 0.0 17.9 Under Construction 22,963.4 80.0 1,076.6 20,953.1 704.7 35.0 In Service 40,796.5 0.0 0.0 0.0 40,792.5 0.0 Withdrawn 281,037.5 0.0 0.0 0.0 0.0 281,037.9 Total at 9/30/2015 51,236.3 5,221.0 23,146.4 41,795.4 283,214.5

Table 12-4 shows the amount of capacity active, in-service, under construction, suspended, or withdrawn for each queue since the beginning of the RTEP process and the total amount of capacity that had been included in each queue. All items in queues A-L are either in service or have been withdrawn. As of September 30, 2015, there are 79,603.8 MW of capacity in queues that are not yet in service, of which 6.6 percent are suspended, 29.1 percent are under construction and 64.4 percent have not begun construction.



Table 12‑4 Capacity in PJM queues (MW): At September 30, 201510

Queue Active In‑ServiceUnder

Construction Suspended Withdrawn TotalA Expired 31-Jan-98 0.0 8,103.0 0.0 0.0 17,347.0 25,450.0B Expired 31-Jan-99 0.0 4,477.5 0.0 0.0 14,620.7 19,098.2C Expired 31-Jul-99 0.0 531.0 0.0 0.0 3,470.7 4,001.7D Expired 31-Jan-00 0.0 850.6 0.0 0.0 7,182.0 8,032.6E Expired 31-Jul-00 0.0 795.2 0.0 0.0 8,021.8 8,817.0F Expired 31-Jan-01 0.0 52.0 0.0 0.0 3,092.5 3,144.5G Expired 31-Jul-01 0.0 1,189.6 0.0 0.0 17,962.3 19,151.9H Expired 31-Jan-02 0.0 702.5 0.0 0.0 8,421.9 9,124.4I Expired 31-Jul-02 0.0 103.0 0.0 0.0 3,728.4 3,831.4J Expired 31-Jan-03 0.0 40.0 0.0 0.0 846.0 886.0K Expired 31-Jul-03 0.0 218.0 0.0 0.0 2,425.4 2,643.4L Expired 31-Jan-04 0.0 256.5 0.0 0.0 4,033.7 4,290.2M Expired 31-Jul-04 0.0 504.8 150.0 0.0 3,705.6 4,360.4N Expired 31-Jan-05 0.0 2,398.8 38.0 0.0 8,090.3 10,527.0O Expired 31-Jul-05 0.0 1,668.2 437.0 0.0 5,466.8 7,572.0P Expired 31-Jan-06 0.0 3,255.2 62.5 210.0 5,110.5 8,638.2Q Expired 31-Jul-06 105.0 3,147.9 1,594.0 0.0 9,686.7 14,533.6R Expired 31-Jan-07 0.0 2,046.4 488.3 800.0 19,420.6 22,755.3S Expired 31-Jul-07 0.0 3,732.3 283.3 360.0 12,706.5 17,082.0T Expired 31-Jan-08 675.0 1,935.0 2,011.8 428.0 22,488.3 27,538.1U Expired 31-Jan-09 700.0 1,125.3 381.9 320.0 30,829.6 33,356.8V Expired 31-Jan-10 1,249.2 2,018.8 1,122.3 460.0 12,036.4 16,886.7W Expired 31-Jan-11 2,015.0 1,179.6 1,542.7 1,628.0 17,942.6 24,307.9X Expired 31-Jan-12 3,026.0 359.0 9,003.4 361.8 17,618.0 30,368.2Y Expired 30-Apr-13 2,718.0 826.6 4,477.5 630.8 17,336.3 25,989.0Z Expired 30-Apr-14 7,398.0 273.5 1,400.3 22.5 5,580.8 14,675.0AA1 Expired 31-Oct-14 10,865.3 5.3 150.3 0.0 1,275.3 12,296.2AA2 Expired 30-Apr-15 13,789.7 0.0 0.0 0.0 2,666.0 16,455.7AB1 Through 30-Sep-15 8,695.1 0.0 3.3 0.0 101.9 8,800.3Total 51,236.3 41,795.4 23,146.4 5,221.0 283,214.5 404,613.6

10 Projects listed as partially in-service are counted as in-service for the purposes of this analysis.

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Distribution of Units in the QueuesTable 12-5 shows the projects under construction, suspended, or active, by unit type, and control zone.11 As of September 30, 2015, 79,603.8 MW of capacity were in generation request queues for construction through 2024, compared to 77,461.3 MW at June 30, 2015.12 Table 12-5 also shows the planned retirements for each zone.

Table 12‑5 Queue capacity by LDA, control zone and fuel (MW): At September 30, 201513

LDA Zone CC CT Diesel Hydro Nuclear Solar Steam Storage WindTotal Queue

CapacityPlanned

RetirementsEMAAC AECO 1,276.0 302.5 0.0 0.0 0.0 49.2 0.0 20.0 373.0 2,020.7 8.0

DPL 822.0 17.0 2.0 0.0 0.0 425.5 0.0 22.0 749.6 2,038.1 34.0JCPL 2,869.0 0.0 0.6 0.0 0.0 540.6 0.0 180.0 0.0 3,590.2 614.5PECO 3,614.0 0.0 9.8 10.0 0.0 0.0 0.0 40.0 0.0 3,673.8 50.8PSEG 3,033.9 516.0 13.6 0.0 0.0 155.1 0.0 0.0 0.0 3,718.6 611.0EMAAC Total 11,614.9 835.5 26.0 10.0 0.0 1,170.4 0.0 262.0 1,122.6 15,041.4 1,318.3

SWMAAC BGE 0.0 0.0 30.3 0.0 0.4 23.1 132.0 20.1 0.0 205.9 260.0Pepco 2,725.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2,725.6 1,204.0SWMAAC Total 2,725.6 0.0 30.3 0.0 0.4 23.1 132.0 20.1 0.0 2,931.5 1,464.0

WMAAC Met-Ed 1,250.0 86.6 0.0 16.8 0.0 3.0 401.0 0.0 0.0 1,757.4 0.0PENELEC 3,932.0 592.3 161.8 0.0 40.0 13.5 0.0 68.4 473.3 5,281.3 10.4PPL 6,102.0 0.0 24.9 0.0 0.0 129.0 16.0 30.0 518.5 6,820.4 0.0WMAAC Total 11,284.0 678.9 186.7 16.8 40.0 145.5 417.0 98.4 991.8 13,859.1 10.4

Non-MAAC AEP 6,111.0 51.0 9.8 102.0 34.0 101.7 220.0 62.0 6,542.0 13,233.5 0.0APS 5,792.4 0.0 147.4 0.0 58.2 219.6 1,733.7 51.0 663.6 8,665.9 0.0ATSI 4,052.0 0.8 40.7 0.0 0.0 0.0 0.0 0.0 518.0 4,611.5 0.0ComEd 5,200.8 603.3 26.6 0.0 22.7 14.0 27.0 120.6 3,387.0 9,402.0 0.0DAY 0.0 0.0 1.9 0.0 0.0 23.4 12.0 20.0 300.0 357.3 0.0DEOK 513.0 0.0 6.4 0.0 112.0 125.0 50.0 18.0 0.0 824.4 0.0DLCO 205.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 205.0 0.0Dominion 5,451.3 0.0 2.0 1,594.0 0.0 1,760.4 62.5 130.0 1,472.1 10,472.3 323.0EKPC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 149.0Non-MAAC Total 27,325.5 655.1 234.7 1,696.0 226.9 2,244.1 2,105.2 401.6 12,882.7 47,771.8 472.0

Total 52,950.0 2,169.5 477.7 1,722.8 267.3 3,583.1 2,654.2 782.1 14,997.1 79,603.8 3,264.7

11 Unit types designated as reciprocating engines are classified as diesel.12 Since wind resources cannot be dispatched on demand, PJM rules previously required that the unforced capacity of wind resources

be derated to 20 percent of installed capacity until actual generation data are available. Beginning with Queue U, PJM derates wind resources to 13 percent of installed capacity until there is operational data to support a different conclusion. PJM derates solar resources to 38 percent of installed capacity. Based on the derating of 14,997.1 MW of wind resources and 3,583.1 MW of solar resources, the 79,603.8 MW currently active in the queue would be reduced to 64,334.8 MW.

13 This data includes only projects with a status of active, under-construction, or suspended.

A significant shift in the distribution of unit types within the PJM footprint continues to develop as natural gas fired units enter the queue and steam units retire. While 55,630.8 MW of gas fired capacity are in the queue, only 1,947.0 MW of coal fired steam capacity are in the queue. The only new coal project since the second quarter of 2014 is the new Hatfield unit, with 1,710 MW of capacity. This project entered the queue in October 2014 and is intended to replace three coal units retired in October 2013 at the same location. With respect to retirements, 1,811.0 MW of coal fired steam capacity

and 282.8 MW of natural gas capacity are slated for deactivation. The replacement of coal steam units by units burning natural gas could significantly affect future congestion, the role of firm and interruptible gas supply, and natural gas supply infrastructure.

Planned RetirementsAs shown in Table 12-6, 27,029.0 MW have been, or are planned to be, retired between 2011 and 2020. Of that, 3,264.7 MW are planned to retire after 2015. In the first nine months of 2015, 9,847.3 MW were retired, of which 7,661.8 MW were coal units. The coal unit retirements were a result of the EPA’s Mercury and Air Toxics Standards (MATS) and low gas prices.



Table 12‑6 Summary of PJM unit retirements by fuel (MW): 2011 through 2020

Coal Diesel Heavy Oil KeroseneLandfill

Gas Light OilNatural

Gas Nuclear WindWood Waste Total

Retirements 2011 543.0 0.0 0.0 0.0 0.0 63.7 522.5 0.0 0.0 0.0 1,129.2 Retirements 2012 5,907.9 0.0 0.0 0.0 0.0 788.0 250.0 0.0 0.0 16.0 6,961.9 Retirements 2013 2,589.9 2.9 166.0 0.0 3.8 85.0 0.0 0.0 0.0 8.0 2,855.6 Retirements 2014 2,427.0 50.0 0.0 184.0 15.3 0.0 294.0 0.0 0.0 0.0 2,970.3 Retirements 2015 7,661.8 10.3 0.0 644.2 0.0 212.0 1,319.0 0.0 0.0 0.0 9,847.3 Planned Retirements 2015 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 10.4 0.0 10.4 Planned Retirements Post-2015 1,811.0 59.0 108.0 0.0 0.0 0.0 661.8 614.5 0.0 0.0 3,254.3 Total 20,940.6 122.2 274.0 828.2 19.1 1,148.7 3,047.3 614.5 10.4 24.0 27,029.0

A map of these retirements between 2011 and 2020 is shown in Figure 12-1.

Figure 12‑1 Map of PJM unit retirements: 2011 through 2020

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The list of pending retirements is shown in Table 12-7.

Table 12‑7 Planned retirement of PJM units: as of September 30, 2015

Unit ZoneICAP

(MW) Fuel Unit TypeProjected

Deactivation DateYorktown 1-2 Dominion 323.0 Coal Steam 31-Mar-16Dale 3-4 EKPC 149.0 Coal Steam 16-Apr-16BL England Diesels AECO 8.0 Diesel Diesel 31-May-16Riverside 4 BGE 74.0 Natural gas Steam 01-Jun-16McKee 1-2 DPL 34.0 Heavy Oil Combustion Turbine 31-May-17Sewaren 1-4 PSEG 453.0 Kerosene Combustion Turbine 01-Nov-17Bayonne Cogen Plant (CC) PSEG 158.0 Natural gas Steam 01-Nov-18MH50 Marcus Hook Co-gen PECO 50.8 Natural gas Steam 13-May-19Chalk Point 1-2 Pepco 667.0 Coal Steam 31-May-19Dickerson 1-3 Pepco 537.0 Coal Steam 31-May-19Oyster Creek JCPL 614.5 Nuclear Nuclear 31-Dec-19Wagner 2 BGE 135.0 Coal Steam 01-Jun-20Arnold (Green Mountain) Wind Farm PENELEC 10.4 Wind Wind 05-Nov-15Perryman 2 BGE 51.0 Diesel Combustion Turbine 01-Jan-16Total 3,264.7

Table 12‑8 Retirements by fuel type: 2011 through 2020

Number of Units Avg. Size (MW)Avg. Age at

Retirement (Years) Total MW PercentCoal 127 164.9 55.9 20,940.6 77.5%Diesel 7 17.5 42.7 122.2 0.5%Heavy Oil 4 68.5 57.5 274.0 1.0%Kerosene 20 41.4 45.5 828.2 3.1%Landfill Gas 4 4.8 14.8 19.1 0.1%Light Oil 15 76.6 43.8 1,148.7 4.2%Natural Gas 51 59.8 46.3 3,047.3 11.3%Nuclear 1 614.5 50.0 614.5 2.3%Wind 1 10.4 15.0 10.4 0.0%Wood Waste 2 12.0 23.5 24.0 0.1%Total 232 116.5 0.0 27,029.0 100.0%

Table 12-8 shows the capacity, average size, and average age of units retiring in PJM, from 2011 through 2020, while Table 12-9 shows these retirements by state. The majority, 77.5 percent, of all MW retiring during this period are coal steam units. These units have an average age of 55.9 years and an average size of 164.9 MW. More than half of them, 51.5 percent, are located in either Ohio or Pennsylvania. Retirements have generally consisted of smaller sub-critical coal steam units and those without adequate environmental controls to remain viable beyond 2015.



Table 12‑9 Retirements (MW) by fuel type and state: 2011 through 2020

State Coal Diesel Heavy Oil KeroseneLandfill

Gas Light OilNatural

Gas Nuclear WindWood Waste Total

DC 0.0 0.0 0.0 0.0 0.0 788.0 0.0 0.0 0.0 0.0 788.0 DE 254.0 0.0 34.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 288.0 IL 1,624.0 0.0 0.0 0.0 6.4 0.0 0.0 0.0 0.0 0.0 1,630.4 IN 982.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 982.0 KY 995.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 995.0 MD 1,454.0 51.0 74.0 0.0 0.0 0.0 115.0 0.0 0.0 0.0 1,694.0 NC 0.0 0.0 0.0 0.0 0.0 31.0 0.0 0.0 0.0 0.0 31.0 NJ 136.0 8.0 0.0 828.2 4.7 212.0 2,680.5 614.5 0.0 0.0 4,483.9 OH 5,658.6 60.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5,718.9 PA 5,145.0 0.0 166.0 0.0 8.0 117.7 251.8 0.0 10.4 24.0 5,722.9 VA 2,051.0 2.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2,053.9 WV 2,641.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2,641.0 Total 20,940.6 122.2 274.0 828.2 19.1 1,148.7 3,047.3 614.5 24.0 27,029.0

Section 12 Planning


Actual Generation Deactivations in 2015Table 12-10 shows the units that were deactivated in 2015.

Table 12‑10 Unit deactivations in 2015Company Unit Name ICAP (MW) Primary Fuel Zone Name Average Age (Years) Retirement DateCalpine Corporation Cedar 1 44.0 Kerosene AECO 43 28-Jan-15First Energy Eastlake 2 109.0 Coal ATSI 62 06-Apr-15First Energy Eastlake 1 109.0 Coal ATSI 62 09-Apr-15First Energy Eastlake 3 109.0 Coal ATSI 61 10-Apr-15First Energy Ashtabula 5 210.0 Coal ATSI 57 11-Apr-15First Energy Lake Shore 18 190.0 Coal ATSI 53 13-Apr-15First Energy Lake Shore EMD 4.0 Diesel ATSI 49 15-Apr-15NRG Energy Will County 251.0 Coal ComEd 58 15-Apr-15EKPC Dale 1-2 46.0 Coal EKPC 61 16-Apr-15Calpine Corporation Cedar 2 21.6 Kerosene AECO 43 01-May-15NRG Energy Gilbert 1-4 98.0 Natural gas JCPL 45 01-May-15NRG Energy Glen Gardner 1-8 160.0 Natural gas JCPL 44 01-May-15Calpine Corporation Middle 1-3 74.7 Kerosene AECO 45 01-May-15Calpine Corporation Missouri Ave B, C, D 57.9 Kerosene AECO 46 01-May-15NRG Energy Werner 1-4 212.0 Light oil JCPL 43 01-May-15PSEG Bergen 3 21.0 Natural gas PSEG 48 01-Jun-15AEP Big Sandy 2 800.0 Coal AEP 46 01-Jun-15PSEG Burlington 8, 11 205.0 Kerosene PSEG 48 01-Jun-15AEP Clinch River 3 230.0 Coal AEP 54 01-Jun-15PSEG Edison 1-3 504.0 Natural gas PSEG 44 01-Jun-15PSEG Essex 10-11 352.0 Natural gas PSEG 44 01-Jun-15PSEG Essex 12 184.0 Natural gas PSEG 43 01-Jun-15AEP Glen Lyn 5-6 325.0 Coal AEP 65 01-Jun-15AES Corporation Hutchings 1-3, 5-6 271.8 Coal DAY 65 01-Jun-15AEP Kammer 1-3 600.0 Coal AEP 57 01-Jun-15AEP Kanawha River 1-2 400.0 Coal AEP 62 01-Jun-15PSEG Mercer 3 115.0 Kerosene PSEG 48 01-Jun-15Duke Energy Kentucky Miami Fort 6 163.0 Coal DEOK 55 01-Jun-15AEP Muskingum River 1-5 1,355.0 Coal AEP 60 01-Jun-15PSEG National Park 1 21.0 Kerosene PSEG 46 01-Jun-15AEP Picway 5 95.0 Coal AEP 60 01-Jun-15PSEG Sewaren 6 105.0 Kerosene PSEG 50 01-Jun-15AEP Sporn 1-4 580.0 Coal AEP 64 01-Jun-15AEP Tanners Creek 1-4 982.0 Coal AEP 60 01-Jun-15NRG Energy Shawville 4 175.0 Coal PENELEC 55 02-Jun-15NRG Energy Shawville 3 175.0 Coal PENELEC 56 07-Jun-15NRG Energy Shawville 1 122.0 Coal PENELEC 61 12-Jun-15NRG Energy Shawville 2 125.0 Coal PENELEC 61 14-Jun-15Portsmouth Genco Lake Kingman 115.0 Coal Dominion 27 19-Jun-15AES Corporation AES Beaver Valley 124.0 Coal DLCO 28 01-Sep-15First Energy Burger EMD 6.3 Diesel ATSI 43 18-Sep-15Total 9,847.3



Generation MixAs of September 30, 2015, PJM had an installed capacity of 185,656.0 MW (Table 12-11). This measure differs from Capacity Market installed capacity because it includes energy-only units, excludes all external units, and uses non-derated values for solar and wind resources.

Table 12‑11 Existing PJM capacity: At September 30, 2015 (By zone and unit type (MW))14

Zone CC CT Diesel Fuel Cell Hydroelectric Nuclear Solar Steam Storage Wind TotalAECO 901.9 507.7 22.6 0.0 0.0 0.0 41.7 815.9 0.0 7.5 2,297.3 AEP 4,900.0 3,682.2 77.1 0.0 1,071.9 2,071.0 0.0 18,897.8 4.0 1,953.2 32,657.2 AP 1,129.0 1,214.9 47.9 0.0 86.0 0.0 36.1 5,409.0 27.4 1,058.5 9,008.8 ATSI 685.0 1,617.4 74.0 0.0 0.0 2,134.0 0.0 5,813.0 0.0 0.0 10,323.4 BGE 0.0 840.0 18.4 0.0 0.0 1,716.0 0.0 2,995.5 0.0 0.0 5,569.9 ComEd 3,146.1 7,244.0 93.8 0.0 0.0 10,473.5 9.0 5,166.1 76.0 2,431.9 28,640.4 DAY 0.0 1,368.5 47.5 0.0 0.0 0.0 1.1 2,908.0 40.0 0.0 4,365.1 DEOK 47.2 654.0 0.0 0.0 0.0 0.0 0.0 3,730.0 2.0 0.0 4,433.2 DLCO 244.0 15.0 0.0 0.0 6.3 1,777.0 0.0 784.0 0.0 0.0 2,826.3 Dominion 5,493.6 3,874.8 153.8 0.0 3,589.3 3,581.3 22.7 7,890.0 0.0 0.0 24,605.5 DPL 1,498.5 1,820.4 96.1 30.0 0.0 0.0 4.0 1,620.0 0.0 0.0 5,069.0 EKPC 0.0 774.0 0.0 0.0 70.0 0.0 0.0 1,882.0 0.0 0.0 2,726.0 JCPL 1,692.5 763.1 19.9 0.0 400.0 614.5 104.3 10.0 0.0 0.0 3,604.3 Met-Ed 2,111.0 406.5 41.4 0.0 19.0 805.0 0.0 200.0 0.0 0.0 3,582.9 PECO 3,209.0 836.0 2.9 0.0 1,642.0 4,546.8 3.0 979.1 1.0 0.0 11,219.8 PENELEC 0.0 407.5 52.2 0.0 512.8 0.0 0.0 6,793.5 0.0 930.9 8,696.9 Pepco 230.0 1,091.7 9.9 0.0 0.0 0.0 0.0 3,649.1 0.0 0.0 4,980.7 PPL 1,807.9 616.2 55.5 0.0 706.6 2,520.0 15.0 5,169.9 20.0 219.7 11,130.8 PSEG 3,091.3 1,132.0 11.1 0.0 5.0 3,493.0 134.0 2,050.1 2.0 0.0 9,918.5 RECO 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Total 30,187.0 28,865.9 824.1 30.0 8,108.9 33,732.1 370.9 76,763.0 172.4 6,601.7 185,656.0

Table 12‑12 PJM capacity (MW) by age (years): At September 30, 2015Age (years) CC CT Diesel Fuel Cell Hydroelectric Nuclear Solar Steam Storage Wind TotalLess than 20 25,808.5 21,457.0 563.4 30.0 189.6 0.0 370.9 4,601.9 172.4 6,601.7 59,795.420 to 40 3,936.5 2,913.9 88.8 0.0 3,557.2 22,893.9 0.0 25,688.7 0.0 0.0 59,079.040 to 60 442.0 4,495.0 169.9 0.0 3,010.0 10,838.2 0.0 44,835.9 0.0 0.0 63,791.0More than 60 0.0 0.0 2.0 0.0 1,352.1 0.0 0.0 1,636.5 0.0 0.0 2,990.6Total 30,187.0 28,865.9 824.1 30.0 8,108.9 33,732.1 370.9 76,763.0 172.4 6,601.7 185,656.0

14 The capacity described in this section refers to all non-derated installed capacity in PJM, regardless of whether the capacity entered the RPM auction. This table previously included external units.

Figure 12-2 and Table 12-12 show the age of PJM generators by unit type. Units older than 40 years comprise 66,781.6 MW, or 36.0 percent, of the total capacity of 185,656.0 MW.

Section 12 Planning


Figure 12‑2 PJM capacity (MW) by age (years): At September 30, 2015

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

CC CT Diesel Fuel Cell Hydro Nuclear Solar Steam Storage Wind

MW in

Ser

vice

Unit Type

> 60

40 to 60

20 to 40

< 20

Table 12-13 shows the effect that expected retirements and new generation in the queues would have on the existing generation mix five years from now. Even though 66,781.6 MW of the total capacity are more than 40 years old, only 3,264.7 MW of these are planned to retire within the next five years. The expected role of gas-fired generation depends on projects in the queues and retirement of coal-fired generation. Existing capacity is 41.4 percent steam, which will be reduced to 31.0 percent by 2020 as a result of the addition of 41,848.6 MW of planned CC capacity. The percentage of CC capacity would increase from 16.3 percent to 29.7 percent of total capacity in PJM in 2020.

Table 12‑13 Expected capacity (MW) in five years: as of September 30, 201515

LDA Unit Type

Current Generator

CapacityPercent of Area Total

Planned Additions

Planned Retirements

Estimated Capacity in 5

YearsPercent of Area Total

EMAAC Combined Cycle 10,393.2 32.4% 10,237.9 0.0 20,631.1 46.4%Combustion Turbine 5,059.2 15.8% 835.5 0.0 5,894.7 13.3%Diesel 152.6 0.5% 26.0 8.0 170.6 0.4%Fuel Cell 30.0 0.1% 0.0 0.0 30.0 0.1%Hydroelectric 2,047.0 6.4% 0.0 0.0 2,047.0 4.6%Nuclear 8,654.3 27.0% 10.0 614.5 8,049.8 18.1%Solar 287.0 0.9% 1,170.4 0.0 1,457.4 3.3%Steam 5,475.1 17.1% 0.0 695.8 4,779.3 10.8%Storage 3.0 0.0% 262.0 0.0 265.0 0.6%Wind 7.5 0.0% 1,122.6 0.0 1,130.1 2.5%Total 32,108.9 100.0% 13,664.4 1,318.3 44,455.0 100.0%

SWMAAC Combined Cycle 230.0 2.2% 2,725.6 0.0 2,955.6 24.7%Combustion Turbine 1,931.7 18.3% 0.0 51.0 1,880.7 15.7%Diesel 28.3 0.3% 30.3 0.0 58.6 0.5%Nuclear 1,716.0 16.3% 0.0 0.0 1,716.0 14.3%Steam 6,644.6 63.0% 132.0 1,413.0 5,363.6 44.8%Total 10,550.6 100.0% 2,887.9 1,464.0 11,974.5 100.0%

WMAAC Combined Cycle 3,918.9 16.7% 11,284.0 0.0 15,202.9 34.2%Combustion Turbine 1,430.2 6.1% 678.9 0.0 2,109.1 4.7%Diesel 149.1 0.6% 186.7 0.0 335.8 0.8%Hydroelectric 1,238.4 5.3% 40.0 0.0 1,278.4 2.9%Nuclear 3,325.0 14.2% 16.8 0.0 3,341.8 7.5%Solar 15.0 0.1% 145.5 0.0 160.5 0.4%Steam 12,163.4 52.0% 417.0 0.0 12,580.4 28.3%Storage 20.0 0.1% 98.4 0.0 118.4 0.3%Wind 1,150.6 4.9% 991.8 10.4 2,132.0 4.8%Total 23,410.6 100.0% 13,859.1 10.4 37,259.2 100.0%

RTO Combined Cycle 15,644.9 13.1% 27,325.5 0.0 42,970.4 26.0%Combustion Turbine 20,444.8 17.1% 655.1 0.0 21,099.9 12.8%Diesel 494.1 0.4% 234.7 0.0 728.8 0.4%Hydroelectric 4,823.5 4.0% 226.9 0.0 5,050.4 3.1%Nuclear 20,036.8 16.8% 102.0 0.0 20,138.8 12.2%Solar 69.0 0.1% 2,244.1 0.0 2,313.1 1.4%Steam 52,479.9 43.9% 2,105.2 472.0 54,113.1 32.8%Storage 149.4 0.1% 401.6 0.0 551.0 0.3%Wind 5,443.6 4.6% 12,632.7 0.0 18,076.3 11.0%Total 119,586.0 100.0% 45,927.8 472.0 165,041.8 100.0%

Total 185,656.0 76,339.2 3,264.7 258,730.5

15 Percentages shown in Table 12-13 are based on unrounded, underlying data and may differ from calculations based on the rounded values in the tables.



Generation and Transmission Interconnection Planning ProcessPJM made changes to the queue process in May 2012.16 These changes included reducing the length of the queues, creating an alternate queue for some small projects, and adjustments to the rules regarding suspension rights and Capacity Interconnection Rights (CIR). PJM staff reported on June 11, 2015 that due to these and other process improvements, the study backlog has been significantly reduced. PJM staff also noted that most queue projects are submitted in the last week of the six-month queues, contributing to the study backlog because of the time it takes to resolve deficiencies and enter project parameters into the planning models.17 The Earlier Queue Submittal Task Force (EQSTF) was established in August 2015 to address the issue.18

Interconnection Study PhaseIn the study phase of the interconnection planning process, a series of studies are performed to determine the feasibility, impact, and cost of projects in the queue. Table 12-14 is an overview of PJM’s study process. System impact and facilities studies are often redone when a project is withdrawn in order to determine the impact on the projects remaining in the queue.

Table 12‑14 PJM generation planning process

Milestone Completed Number of

ProjectsPercent of Total

ProjectsAverage

DaysMaximum

DaysNot Started 73 12.1% 553 1,800Feasibility Study 116 19.2% 772 2,555Impact Study 113 18.7% 1,148 3,351Facilities Study 23 3.8% 1,880 3,890Interconnection Service Agreement (ISA) 13 2.2% 865 1,858Wholesale Market Participation Agreement (WMPA) 1 0.2% 519 519Construction Service Agreement (CSA) 4 0.7% 822 1,842Under Construction 195 32.3% 1,782 6,380Suspended 66 10.9% 2,107 4,149Total 604 100.0%

16 See letter from PJM to Secretary Kimberly Bose, Docket No. ER12-1177-000, <http://www.pjm.com/~/media/documents/ferc/2012-filings/20120229-er12-1177-000.ashx>.

17 See presentation by Dave Egan to the Planning Committee PJM, at <http://www.pjm.com/~/media/committees-groups/committees/pc/20150611/20150611-item-09-queue-status-update.ashx>

18 See Earlier Queue Submittal Task Force at <http://www.pjm.com/committees-and-groups/task-forces/eqstf.aspx>

Manual 14B requires PJM to apply a commercial probability factor at the feasibility study stage to improve the accuracy of capacity and cost estimates. The commercial probability factor is based on the historical incidence of projects dropping out of the queue at the impact study stage.19 The impact and facilities studies are performed using the full amount of planned generation in the queues. The actual withdrawal rates are shown in Table 12-15 and Table 12-16.

Table 12-16 shows the milestone status when projects were withdrawn, for all withdrawn projects. Of the projects withdrawn, 48.3 percent were withdrawn before the system impact study was completed. Once an Interconnection Service Agreement (ISA) or a Wholesale Market Participation Agreement (WMPA) is executed, the financial obligation for any necessary transmission upgrades cannot be retracted.20,21 As expected, withdrawing at or beyond this point is uncommon; only 206 projects, or 12.6 percent, of all projects withdrawn were withdrawn after reaching this milestone.

Table 12‑15 Last milestone completed at time of withdrawal: January 1, 1997 through September 30, 2015 Milestone Completed Projects Withdrawn PercentNever Started 176 10.7%Feasibility Study 617 37.6%System Impact Study 536 32.7%Facilities Study 106 6.5%Interconnection Service Agreement (ISA) 37 2.3%Wholesale Market Participation Agreement (WMPA) 115 7.0%Construction Service Agreement (CSA) or beyond 54 3.3%Total 1,641 100.0%

Disregarding projects still active or under construction, Table 12-16 shows, by MW, the rate at which projects drop out of the queue as they move through the process. Out of 264,381.0 MW that entered the queue, 33,328.5 went into service, while the remaining 244,028.0 MW withdrew at some point. Of the

19 See PJM Manual 14B. “PJM Region Transmission Planning Process,” Revision 30 (February 26, 2015), p.70.20 “Generators planning to connect to the local distribution systems at locations that are not under FERC jurisdiction and wish to

participate in PJM’s market need to execute a PJM Wholesale Market Participation Agreement (WMPA)…” instead of an ISA. See PJM Manual 14C. “Generation and Transmission Interconnection Facility Construction,” Revision 08 (December 20, 2012), p.8.

21 See PJM Manual 14C. “Generation and Transmission Interconnection Facility Construction,” Revision 08 (December 20, 2012), p.22.

Section 12 Planning


withdrawals, 53.9 percent happened after the feasibility study was completed, before proceeding to the next milestone.

Table 12‑16 Completed (withdrawn or in service) queue MW: January 1, 1997 through September 30, 2015

Milestone Completed MW in QueuePercent of Total in

Queue MW WithdrawnPercent of Total

WithdrawnEnter Queue 264,381.0 100.0% 20,353.0 8.8%Feasibility Study 244,028.0 92.3% 124,582.6 53.9%System Impact Study 119,445.3 45.2% 48,075.2 20.8%Facility Study 71,370.2 27.0% 23,403.9 10.1%ISA/WMPA 47,966.3 18.1% 8,177.7 3.5%CSA 39,788.7 15.0% 6,460.2 2.8%In Service 33,328.5 12.6% 0.0 0.0%

Table 12-17 and Table 12-18 show the time spent at various stages in the queue process and the completion time for the studies performed. For completed projects, there is an average time of 924 days, or 2.5 years, between entering a queue and going into service. Nuclear and wind projects tend to take longer to go into service averaging 1,419.6 and 1,393.1 days. The average time to go into service for all other fuel types is 710 days. For withdrawn projects, there is an average time of 656 days between entering a queue and withdrawing.

Table 12‑17 Average project queue times (days): At June 30, 2015Status Average (Days) Standard Deviation Minimum MaximumActive 927 698 38 3,890In-Service 924 679 1 4,024Suspended 2,107 781 601 4,149Under Construction 1,782 906 197 6,380Withdrawn 656 657 6 4,249

Table 12-18 presents information on the time in the stages of the queue for those projects not yet in service. Of the 604 projects in the queue as of September 30, 2015, 116 had a completed feasibility study and 195 were under construction.

Table 12‑18 PJM generation planning summary: At September 30, 2015

Milestone Completed Number of

ProjectsPercent of Total

ProjectsAverage

DaysMaximum

DaysNot Started 73 12.1% 553 1,800Feasibility Study 116 19.2% 772 2,555Impact Study 113 18.7% 1,148 3,351Facilities Study 23 3.8% 1,880 3,890Interconnection Service Agreement (ISA) 13 2.2% 865 1,858Wholesale Market Participation Agreement (WMPA) 1 0.2% 519 519Construction Service Agreement (CSA) 4 0.7% 822 1,842Under Construction 195 32.3% 1,782 6,380Suspended 66 10.9% 2,107 4,149Total 604 100.0%

The time it takes to complete a study depends on the backlog and the number of projects in the queue. The time it takes to complete a study does not necessarily depend on the size of the project. Renewable projects (solar, hydro, storage, biomass, wind) account for 62.1 percent of the total number of projects in the queue but only 24.7 percent of the non-derated MW( Table 12-19).

Table 12‑19 Queue details by fuel group: At September 30, 2015Fuel Group Number of Projects Percent of Projects MW Percent MWNuclear 5 0.8% 1,722.8 2.2%Renewable 375 62.1% 19,667.0 24.7%Traditional 224 37.1% 58,214.0 73.1%Total 604 100.0% 79,603.8 100.0%

Role of Transmission Owners in Transmission Planning Study PhaseAccording to PJM Manual 14A, PJM, in coordination with the TOs, conducts the feasibility, system impact and facilities studies for every interconnection queue project. It is clear that the TOs perform the studies.22 The coordination begins with PJM identifying transmission issues resulting from the generation projects. The TOs perform the studies and provide the mitigation requirements for each issue. A facilities study is required only for new generation and

22 See PJM, OATT, Part VI, § 210



significant generation additions and is the study in which the TO is most involved. For a facilities study, the interconnected TO (ITO), as well as any other affected TOs, is required to conduct their own facilities study and provide a summary and results to PJM. PJM compiles these results, along with inputs from the developer, into PJM’s models to confirm that the TOs’ defined upgrades will resolve the issue. PJM writes the final facilities report, which includes the inputs, a description of the issues to be resolved, and the findings of all contributing TOs.23

Of 604 active projects analyzed, the developer and TO are part of the same company for 45 of the projects, or 11,097.4 MW of a total 79,603.9 MW, 13.9 percent of the MW. Where the TO is a vertically integrated company that also owns generation, there is a potential conflict of interest when the TO evaluates the interconnection requirements of new generation which is part of the same company. There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is a competitor to the generation of its parent company.

Table 12-20 is a summary of the number of projects and total MW, by transmission owner parent company, which identifies the number of projects for which the developer and transmission owner are part of the same company. The Dominion Zone has eight related projects which account for 5,867.3 MW, 56.0 percent of the total MW currently in the queue in the Dominion Zone. Renewable projects comprise 3,415.0 MW, 74.1 percent, of unrelated projects in the queue in the Dominion Zone. In contrast, the AEP Zone has 12 related projects, but they account for only 2.8 percent of its total MW currently in the queue.

23 See PJM. “Manual 14A, “Generation and Transmission Interconnection Process,” Revision 17, (January 22, 2015),<http://www.pjm.com/documents/manuals.aspx>

Table 12‑20 Summary of project developer relationship to transmission ownerNumber of Projects Total MW

Parent Company Related Unrelated

Percent Related Related Unrelated

Percent Related

AEP 12 69 14.8% 370.7 12,862.8 2.8%AES 2 5 28.6% 32.0 325.3 9.0%DLCO 0 1 0.0% 0.0 205.0 0.0%Dominion 8 57 12.3% 5,867.3 4,605.0 56.0%Duke 2 7 22.2% 52.0 772.4 6.3%Exelon 8 92 8.0% 2,270.0 11,011.8 17.1%First Energy 2 199 1.0% 1,736.0 22,170.3 7.3%Pepco 0 77 0.0% 0.0 6,784.3 0.0%PPL 0 28 0.0% 0.0 6,820.4 0.0%PSEG 11 24 31.4% 769.4 2,949.2 20.7%Total 45 559 7.5% 11,097.4 68,506.5 13.9%

These projects are shown by fuel type in Table 12-21. Natural gas generators comprise 69.9 percent of the total related MW in this table. Developers of coal and nuclear projects are almost entirely related to the TO, with 95.3 percent and 99.0 percent of MW. Developers are related to the TO for 13.3 percent of the natural gas project MW in the queue and 12.7 percent of the hydro project MW. All other fuel types projects have no more than 1.1 percent of MW in development related to the TO.

Section 12 Planning


Table 12‑21 Developer‑transmission owner relationship by fuel typeMW by Fuel Type

Parent Company

Transmission Owner

Related to Developer

Number of Projects Biomass Coal Diesel Hydro

Landfill Gas

Natural Gas Nuclear Oil Solar Storage Wind

Total MW

AEP AEP Related 12 83.0 34.0 137.0 102.0 14.7 370.7 Unrelated 69 45.0 92.0 15.8 6,019.0 87.0 62.0 6,542.0 12,862.8

AES DAY Related 2 12.0 20.0 32.0 Unrelated 5 1.9 23.4 300.0 325.3

DLCO DLCO Unrelated 1 205.0 205.0 Dominion Dominion Related 8 4,261.3 1,594.0 12.0 5,867.3

Unrelated 57 62.5 2.0 1,190.0 1,760.4 130.0 1,460.1 4,605.0 Duke DEOK Related 2 50.0 2.0 52.0

Unrelated 7 112.0 6.4 513.0 125.0 16.0 772.4 Exelon BGE Related 1 20.0 20.0

Unrelated 28 157.0 0.4 4.0 1.3 3.1 20.2 186.0 ComEd Unrelated 53 22.7 39.9 5,817.8 10.0 124.6 3,387.0 9,402.0 PECO Related 7 2,200.0 10.0 40.0 2,250.0

Unrelated 11 6.1 3.2 1,414.5 1,423.8 First Energy APS Related 2 1,710.0 26.0 1,736.0

Unrelated 60 58.2 17.2 5,920.3 219.6 51.0 663.6 6,929.9 ATSI Unrelated 12 1.7 4,091.8 518.0 4,611.5 JCPL Unrelated 79 2,869.6 540.6 180.0 3,590.2 Met-Ed Unrelated 8 1,336.6 16.8 401.0 3.0 1,757.4 PENELEC Unrelated 40 40.0 4,686.1 13.5 68.4 473.3 5,281.3

Pepco AECO Unrelated 20 1,578.5 49.2 20.0 373.0 2,020.7 DPL Unrelated 49 2.0 839.0 425.4 22.0 749.6 2,038.0 Pepco Unrelated 8 2,725.6 2,725.6

PPL PPL Unrelated 28 16.0 5.0 6,234.9 16.0 30.0 518.5 6,820.4 PSEG PSEG Related 11 766.0 3.4 769.4

Unrelated 24 2,797.5 151.7 2,949.2 Total Related 45 0 1,855 0 34 0 7,390 1,706 0 38 62 12 11,097.4

Unrelated 559 282 92 6 233 97 48,240 17 401 3,428 724 14,985 68,506.5

Regional Transmission Expansion Plan (RTEP)PJM’s Transmission Expansion Advisory Committee (TEAC), made up of PJM staff, is responsible for the Regional Transmission Expansion Plan (RTEP).24 Transmission upgrades can be divided into three categories: network, supplemental, and baseline. Network upgrades are initiated by generation queue projects and are funded by the developers of the generation projects. Supplemental upgrades are initiated and funded by the TOs. Baseline upgrades are initiated by the TEAC to resolve reliability criteria violations not addressed in other ways. The costs of the baseline projects are allocated proportionally to all TOs who will benefit from the upgrade. Per FERC Order 1000, the TEAC solicits proposals via fixed proposal windows to address these needs. The TEAC evaluates the proposals and recommends proposals to the PJM Board of Managers for approval. Retired generators are included in this analysis for one year after their retirement to reflect the ownership of CIRs.24 See PJM Manual 14B. “PJM Region Transmission Planning Process,” Revision 30 (February 26, 2015), Section 2, p.14



On February 17, 2015, baseline projects with an estimated cost of $551.4 million were presented to and approved by the Board. New projects account for $474.4 million of this amount and adjustments to previously approved baseline projects were $77.0 million.25 Table 12-22 shows a summary of the new baseline upgrade costs for each TO.

Table 12‑22 2015 Board approved new baseline upgrades by transmission owner Transmission Owner Baseline Upgrades ($ million)AEP 312.6APS 1.7ComEd 0.7Dominion 118.0EKPC 2.1JCPL 14.8Met-Ed 1.0PECO 1.5PENELEC 5.8PPL 0.8PSEG 15.6Total 474.4

The 2015 RTEP Proposal Window 1 opened on June 19, 2015, and closed on July 20, 2015. The scope for these proposals includes baseline N-1, generation deliverability and common mode outage, N-1-1, and load deliverability.26 PJM received 90 proposals, comprising 26 upgrades and 64 greenfield projects and addressing 292 flow gates in six target zones. PJM staff are currently evaluating these proposals and expect to make a recommendation in October 2015.27

The 2015 RTEP Proposal Window 2 opened on August 5, 2015, and closed on September 4, 2015. The scope for these proposals includes light load analysis and 2020 TO criteria.28

25 See PJM Staff Whitepaper presented to the TEAC at <http://www.pjm.com/~/media/committees-groups/committees/teac/20150409/20150409-february-2015-board-approval-of-rtep-whitepaper.ashx>

26 See “PJM RTEP – 2015 RTEP Proposal Window #1 Problem Statement & Requirements Document,” June 19, 2015 at <http://www.pjm.com/~/media/planning/rtep-dev/expan-plan-process/ferc-order-1000/rtep-proposal-windows/2015-rtep-window-1-problem-statement-and-requirements.ashx>

27 See TEAC webcast of September 1, 2015 at <http://mediastream.pjm.com/2015/0901/teac/2015-rtep-proposal/index.htm>28 See “PJM RTEP – 2015 RTEP Proposal Window #1 Problem Statement & Requirements Document,” August 5, 2015 at <http://www.pjm.

com/~/media/planning/rtep-dev/expan-plan-process/ferc-order-1000/rtep-proposal-windows/2015-rtep-window-2-problem-statement-and-requirements-document.ashx>

Cost Estimates and AllocationsOn October 25, 2012, Schedule 12 of the tariff and Schedule 6 of the OA were changed to address Order No. 1000 reforms to the cost allocation requirements for local and regional transmission planning projects that had been defined in FERC Order No. 890. The new approach was applied for the first time to the 2013 RTEP. Prior to these changes, costs for a portion of reliability projects were allocated on violation-based dfax values, focusing on the contributions that load made to the violation. The new solution based dfax looks at the relative use of the new facility.29 The allocation rules are summarized in Figure 12-1.

Figure 12‑3 RTEP cost allocation rules

29 See PJM Interconnection, L.L.C., 142 FERC ¶ 61,214 (2013)

Section 12 Planning


Artificial Island UpdateArtificial Island is an area in the PSEG Zone in southern New Jersey that includes nuclear units at Salem and at Hope Creek. On April 29, 2013, PJM issued a request for proposal (RFP), seeking technical solutions to improve stability issues, operational performance under a range of anticipated system conditions, and the elimination of potential planning criteria violations in this area. PJM received 26 individual proposals from seven entities, including proposals from the incumbent transmission owner, PSEG, and from non-incumbents. On July 30, 2105, the PJM Board of Managers accepted PJM’s recommendation to assign the project to LS Power, a non-incumbent, PSEG, and PHI with a total cost estimate between $263M and $283M.30 Table 12-23 shows the details of the project allocation.

Table 12‑23 Artificial Island recommended work and cost allocation

Project TaskDesignated Developer

Cost Estimate ($ million)

Primary Allocation (percent)

230kV transmission line under the Delaware River from Salem to a new substation near the 230kV transmission RoW in Delaware utilizing HDD under the river LS Power

146.0 (cost cap) DPL - 99.99%

Associated substation work at Salem PSEG 61.0-74.0 DPL - 99.99% Associated work on the 230kV RoW PHI 0.0 NASVC at New Freedom PSEG 31.0-38.0 DPL - 51.21%OPGW upgrades designated to PSEG and PHI & Artificial Island GSU tap settings upgrade PSEG 25.0 DPL - 51.21%Total 263.0-283.0

PJM received comments from PSEG & PSEG Nuclear, contesting the selection of LS Power for the construction of a 230kV line over the PSEG proposal. They argued that the PSEG proposal was inappropriately modified, resulting in a higher cost and a lower score and that several performance factors, including stability, installation complexity, long term maintenance and operational costs, and operational complexity were excluded. PSEG also argued that LS Power’s cost cap is misleading and was misinterpreted by PJM staff to be more robust than it actually is. Atlantic Grid Holdings also questioned the robustness of the recommended design. On July 14, 2015, PSEG submitted

30 See letter from Terry Boston concerning the Artificial Island Project at <http://www.pjm.com/~/media/documents/reports/board-statement-on-artificial-island-project.ashx>

an adjusted cost cap for their proposal, appealing to PJM to change their recommendation on the basis that their proposal is now even more superior to LS Power’s.31

The inclusion of a cost cap in some of the offers and the inclusion of a cost cap in the decision criteria is an important step in the development of meaningful competition to build transmission projects. Such cost caps should include minimum exceptions and be enforceable.

PJM received objections to the allocation of 99.9 percent of the costs for the 230kV line portion of the Artificial Island project to DPL, based on the new dfax method, including those from the Delaware Public Service Commission (DE PSC), Delaware Division of the Public Advocate, Old Dominion Electric Cooperative (ODEC), the Maryland Public Service Commission (MD PSC), Easton Utilities, and Delaware Governor Jack Markell.

ConEdison and Linden VFTA FERC order issued on September 16, 2010 approved a settlement between PJM and Consolidated Edison (ConEd) that redefined the terms of an agreement between ConEd and PJM to provide power to New York City that had been in place since the 1970s. Part of the settlement included an agreement by both parties that ConEd would be subject to PJM RTEP costs, from which they had been previously exempt.32 The RTEP Baseline Upgrade filings, ER14-972-000 on January 10, 2014, resulted in approximately $1.5 billion in additional baseline transmission enhancements and expansions, of which ConEd was allocated approximately $631 million.33 PJM submitted these projects as amendments to Schedule 12 of the tariff on January 10, 2014.34

On February 10, 2014, ConEd filed a protest to the cost allocation proposal.35 ConEd asserted that the cost allocation proposal is not permitted under the service agreement for transmission service under the PJM Tariff and related

31 See responses to PJM at <http://www.pjm.com/about-pjm/who-we-are/pjm-board/public-disclosures.aspx> 32 132 FERC ¶ 61,221 p.8 (2010).33 See Transmission Expansion Advisory Committee (TEAC) Recommendations to the PJM Board” at <http://www.pjm.com/~/media/

committees-groups/committees/teac/20131211/20131211-december-2013-pjm-board-approval-of-rtep-whitepaper.ashx>34 See PJM Interconnection L.L.C. Docket No. ER14-972-000 (March 7, 2014)35 See Consolidated Edison Company of New York, Inc. Docket No. ER14-972-000 (February 10, 2014).



settlement agreement, and that PJM’s allocation of costs of the PSE&G upgrade to the ConEd Zone is unjust and unreasonable. On March 7, 2014, PJM argued that the filed and approved RTEP cost allocation process was followed, and that ConEd’s cost assignment responsibilities were addressed by the settlement agreement and Schedule 12 of the PJM Tariff.36 ConEd filed a complaint with FERC on November 7, 2014.37 Linden VFT filed a complaint on May 22, 2015.38

The allocations in dispute were a result of the new solution based dfax method of cost allocation. A summary of the disputed cost allocations is shown in Table 12-24. Both complain that the allocations violated Schedule 12 of the tariff and Schedule 6 of the PJM Operating Agreement, which address unreasonable cost allocations.

Table 12‑24 ConEd and Linden disputed cost allocation summaryAllocation ($M) Allocation (%)

Upgrade IDCost estimate

($M) DfaxLoad Ratio ConEd

Linden (ECP) HTP PSEG Other ConEd

Linden (ECP) HTP PSEG Other

Edison Rebuild 46.0 dfax Method 46.0 0.0 29.2 16.8 0.0 0.0 0.0% 63.5% 36.5% 0.0% 0.0% Load Ratio 0.0 0.0 0.0 0.0 0.0 0.0 0.0% 0.0% 0.0% 0.0% 0.0%Sewaren Project 101.0 dfax Method 101.0 51.3 49.7 0.0 0.0 0.0 50.8% 49.2% 0.0% 0.0% 0.0% Load Ratio 0.0 0.0 0.0 0.0 0.0 0.0 0.0% 0.0% 0.0% 0.0% 0.0%Bergen-Linden Corridor (PSEG projects) 1,180.3 dfax Method 785.0 629.1 12.6 68.5 72.7 2.1 80.1% 1.6% 8.7% 9.3% 0.3% Load Ratio 395.4 2.3 0.8 0.8 23.6 367.9 0.6% 0.2% 0.2% 6.0% 93.1%Total 1,327.3 932.0 395.4 682.7 92.3 86.1 96.3 370.0 51.4% 7.0% 6.5% 7.3% 27.9%

Schedule 12 of the tariff states “If Transmission Provider determines in its reasonable engineering judgment that, as a result of applying the provisions of this Section (b)(iii), the dfax analysis cannot be performed or that the results of such dfax analysis are objectively unreasonable, the Transmission Provider may use an appropriate substitute proxy for the Required Transmission Enhancement in conducting the dfax analysis.” Schedule 6 of the PJM Operating Agreement requires PJM to avoid an allocation of unreasonable

36 See PJM Interconnection L.L.C. Docket No. ER14-972-000 (January 10, 2014).37 See “ConEd RTEP Complaint,” Docket No. E15-18-000 ( November 7, 2014)38 See “Complaint and Request for Fast Track Processing of Linden VFT,LLC,” Docket No.EL15-67-000 (May 22, 2015)

costs in the RTEP process.39 40 Order 1000 states that “costs must be allocated in a way that is roughly commensurate with benefits.”41

ConEd argued that the cost allocation is “objectively unreasonable” and requested “an appropriate substitute proxy.” ConEd’s complaint was not that the solution based dfax method was necessarily faulty, but that the assumptions and inputs that PJM used to model ConEd were inaccurate and resulted in an over allocation to ConEd, Linden VFT, and Hudson Transmission Partners (HTP), and an under allocation to PSEG. PJM responded.42

FERC ruled on ConEd’s complaint on June 18, 2015. FERC accepted the PJM allocation and found that the dfax method, as applied, was not faulty.43 On July 20, 2015, ConEd, Linden VFT, and the New York Public Service Commission requested rehearing on the grounds that PJM and the TOs failed to address or rebut the claim that benefits do not match allocation.44

39 See PJM, Intra-PJM Tariffs, OATT, Schedule 12 § (b)(iii)(G)40 See PJM Operating Agreement, § 1.4(d)(ii)41 See FERC Order 1000-B, §3, Paragraph 6642 See PJM, Intra-PJM Tariffs, OATT, Schedule 12 § (b)(iii)(I)43 See FERC Order issued June 18, 2015, Docket No. ER14-972-002, <http://www.pjm.com/~/media/documents/ferc/2015-orders/20150618-

er14-972-002.ashx>.44 See “Order Granting Rehearing for Further Consideration re Consolidated Edison Company of New York, Inc v. PJM Interconnection, L.L.C

et al.”, Docket no. EL15-18-000 (August 10, 2015).

Section 12 Planning


TranSourceTranSource LLC stated, in a complaint filed on June 23, 2015, that PJM is not being transparent with respect to the development of its cost estimates in the System Impact Study (SIS) phase of three TranSource transmission projects. These projects were intended to be used to procure incremental auction revenue rights (IARR). TranSource seeks an order directing PJM to provide data and working papers related to the SIS sufficient to fully evaluate the basis of cost estimates that TranSource considers excessive. PJM responded that it has provided all work papers relevant to the SIS and objects to the complaint on procedural grounds.45 On September 24, 2015, the Commission issued an order establishing hearing and settlement judge procedures.46 The MMU is participating in this process.

Backbone FacilitiesPJM backbone projects are a subset of baseline upgrade projects that have been given the informal designation of backbone due to their relative significance. Backbone upgrades are on the extra high voltage (EHV) system and resolve a wide range of reliability criteria violations and market congestion issues. The current backbone projects are Mount Storm-Doubs, Jacks Mountain, Susquehanna-Roseland, and Surry Skiffes Creek 500kV. Figure 12-4 shows the location of these four projects.

45 See Motion to Dismiss Complaint and Answer to Complaint Submitted on Behalf of PJM Interconnection, L.L.C., Docket No. EL15-79-000 (July 10, 2015).

46 152 FERC ¶ 61,229.

Figure 12‑4 PJM Backbone Projects

The Mount Storm-Doubs transmission line, which serves West Virginia, Virginia, and Maryland, was originally built in 1966. The structures and equipment are approaching the end of their expected service life and require replacement to ensure reliability. The first two phases, the line rebuild and the energizing of the Mount Storm switchyard, are complete. Construction plans for Phase 3, consisting of additional upgrades to the Mount Storm switchyard, are under development. Completion of this phase is expected by the end of 2015.47

The Jacks Mountain project is required to resolve voltage problems for load deliverability starting June 1, 2017. Jacks Mountain will be a new 500kV substation connected to the existing Conemaugh-Juniata and Keystone-Juniata 500kV circuits. This project is currently in the engineering and design phase. Transmission foundations are planned for fall 2015. Below grade construction of the sub-station is scheduled to be completed by September 2016, and above grade, relay/control construction, is planned for October 2016-June 2017.48

47 See Dominion “Mt. Storm-Doubs,” which can be accessed at: <http://www.pjm.com/planning/rtep-upgrades-status/backbone-status/mount-storm-doubs.aspx>.

48 See “Jacks Mountain,” which can be accessed at: <http://www.pjm.com/planning/rtep-upgrades-status/backbone-status/jacks-mountain.aspx>.



The Susquehanna-Roseland project is required to resolve reliability criteria violations starting June 1, 2012. Susquehanna-Roseland is a new 101-mile 500 kV transmission line connecting the Susquehanna, Lackawanna, Hopatcong, and Roseland buses. PPL is responsible for the first two legs and PSEG for the third. The Susquehanna-Lackawanna portion went into service on September 23, 2014, and the Lackawanna–Hopatcong portion was energized on May 11, 2015. The Hopatcong – Roseland leg was placed in service on April 1, 2014.49 This project is now complete.

The Surry Skiffes Creek 500kV was initiated in the fall of 2014 to relieve the overload of the James River Crossing Double Circuit Towerline anticipated to result from the retirement of Chesapeake units 1-4, which occurred in December 2014, and Yorktown 1, which is pending. It will include a new 7.7 mile 500kV line between Surry and Skiffes, a new 20.25 mile 230kV line between Skiffes Creek and Whealton, and a new Skiffes Creek 500/230kV switching station. PJM’s required in service date for the 500kv portion was June 1, 2015. This project has been delayed by legal challenges. BASF Corporation raised environmental concerns with the siting and the design. James City County and James River Association (JCC) argued that the switching station is not part of the transmission line and therefore should be subject to local zoning ordinances. In an April 16, 2015, ruling, the Supreme Court of Virginia rejected BASF’s claim but agreed with JCC.50 On April 30, 2015, Dominion filed a petition for rehearing, which was rejected, and the case was remanded to the State Corporation Commission (SCC). The SCC issued an order on June 5, 2015, stressing the need for this project to be completed.51 Dominion has begun the foundation work on existing transmission lines at James River Bridge and expects to have it completed by the end of 2015. Dominion expects to energize both the 230kV line and the 500kV line by January 31, 2017.52

49 See “Susquehanna-Roseland,” which can be accessed at: <http://www.pjm.com/planning/rtep-upgrades-status/backbone-status/ susquehanna-roseland.aspx>.

50 BASF Corporation v SCC, et al., Record No. 141009 et al.51 See SCC order, June 5, 2015 at <https://www.dom.com/library/domcom/pdfs/electric-transmission/surry-skiffes-creek/scc-order-060515.

pdf> 52 See “Surry-Skiffes Creek 500kV and Skiffes Creek-Whealton 230kV Projects,” which can be accessed at: <https://www.dom.com/corporate/

what-we-do/electricity/transmission-lines-and-projects/surry-skiffes-creek-500kv-and-skiffes-creek-whealton-230kv-projects>.

Transmission Facility OutagesScheduling Transmission Facility Outage RequestsPJM designates some transmission facilities as reportable. A transmission facility is reportable if a change in its status can affect a transmission constraint on any Monitored Transmission Facility or could impede free-flowing ties within the PJM RTO and/or adjacent areas. If a transmission facility is not modeled in the PJM EMS or the facility is not expected to significantly impact PJM system security or congestion management, it is not reportable.53 When one of the reportable transmission facilities needs to be taken out of service, the TO is required to submit an outage request as early as possible. The outages are categorized by duration: greater than 30 calendar days; less than or equal to 30 calendar days and greater than five calendar days; or less than or equal to five calendar days. Table 12-25 shows that 79.2 percent of the requested outages were planned for five days or shorter and 5.4 percent of requested outages were planned for longer than 30 days in the first nine months of 2015. All of the outage data in this section are for outages scheduled to occur in the first nine months of 2014 and 2015, regardless of when they were initially submitted.54

Table 12‑25 Transmission facility outage request summary by planned duration: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)Planned Duration (Days) Outage Requests Percent Outage Requests Percent<=5 11,480 80.4% 11,457 79.2%>5 & <=30 2,040 14.3% 2,220 15.4%>30 763 5.3% 781 5.4%Total 14,283 100.0% 14,458 100.0%

After receiving a transmission facility outage request from a TO, PJM assigns a received status to the request, based on its submission date, outage planned starting and ending date, and outage planned duration. The received status can be on time, late or past deadline, as defined in Table 12-26.55 The purpose of

53 See PJM. “Manual 3a: Energy Management System (EMS) Model Updates and Quality Assurance (QA), Revision 9 (January 22, 2015).54 The hotline tickets, EMS tripping tickets or test outage tickets were excluded. We only included all the transmission outage tickets

submitted by PJM internal companies which are currently active.55 See “PJM. “Manual 3: Transmission Operations,” Revision 47A (July 1, 2015), p.58.

Section 12 Planning


the rules is to require the TOs to submit transmission facility outages prior to the Financial Transmission Right (“FTR”) auctions so that market participants have complete information on which to base their FTR bids.56

Table 12‑26 PJM transmission facility outage request received status definitionPlanned Duration (Days) Ticket Submission Date Received Status

<=5Before the 1st of the month one month prior to the starting month of the outage On TimeAfter or on the 1st of the month one month prior to the starting month of the outage LateAfter 8:00AM three days prior to the outage Past Deadline

> 5 & <=30Before the 1st of the month six months prior to the starting month of the outage On TimeAfter or on the 1st of the month six months prior to the starting month of the outage LateAfter 8:00AM three days prior to the outage Past Deadline

>30The earlier of either February 1st or the 1st of the month six months prior to the starting month the outage On TimeAfter or on the earlier of either February 1st or the 1st of the month six months prior to the starting month the outage LateAfter 8:00AM three days prior to the outage Past Deadline

Table 12-27 shows a summary of requests by received status. In the first nine months of 2015, 49.3 percent of outage requests received were late.

Table 12‑27 Transmission facility outage request summary by received status: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)

Planned Duration (Days) On Time Late TotalPercent

Late On Time Late TotalPercent

Late<=5 5,857 5,623 11,480 49.0% 5,981 5,476 11,457 47.8%>5 & <=30 1,014 1,026 2,040 50.3% 1,068 1,152 2,220 51.9%>30 323 440 763 57.7% 283 498 781 63.8%Total 7,194 7,089 14,283 49.6% 7,332 7,126 14,458 49.3%

56 See 97 FERC ¶ 61,010 (October 3, 2001).

Once received, PJM processes outage requests in priority order: emergency transmission outage request, transmission outage requests submitted on time, and transmission submitted late. If two outage requests submitted by different transmission owners are expected to occur during the same period, the outage submitted first is processed first by PJM. If a request has an emergency flag, it has the highest priority and will be approved even if submitted past its deadline after PJM determines that the outage does not result in Emergency Procedures.57 PJM will approve all transmission outage requests that are submitted on time and do not jeopardize the reliability of the PJM system. PJM will approve all transmission outage request that are submitted late and do not cause congestion on the PJM system. PJM retains the right to deny all transmission outage request that are submitted past deadline unless the request is an emergency. Table 12-28 is a summary of outage requests by emergency status. Of all outage requests submitted in the first nine months of 2015, 14.2 percent were for emergency outages.

Table 12‑28 Transmission facility outage request summary by emergency: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)Planned Duration (Days) Emergency

Non Emergency Total

Percent Emergency Emergency

Non Emergency Total

Percent Emergency

<=5 1,829 9,651 11,480 15.9% 1,653 9,804 11,457 14.4%>5 & <=30 275 1,765 2,040 13.5% 315 1,905 2,220 14.2%>30 113 650 763 14.8% 85 696 781 10.9%Total 2,217 12,066 14,283 15.5% 2,053 12,405 14,458 14.2%

After PJM determines that a late request may cause congestion, PJM informs the Transmission Owner of solutions available to eliminate the congestion. If a generator planned or maintenance outage request is contributing to the congestion, PJM can request the Generation Owner to defer the outage. If no solutions are available, PJM may require the Transmission Owner to reschedule or cancel the outage. Table 12-29 is a summary of outage requests by congestion status. Of all outage requests submitted in the first nine months of 2015, 10.0 percent were expected to cause congestion and the percentage of outage requests flagged for congestion is similar across the categories

57 PJM. “Manual 3: Transmission Outages,” Revision: 47A (July 1, 2015), p. 67 and p.68.



of planned duration. Of all the outage requests that were expected to cause congestion, 80 requests were denied by PJM in the first nine months of 2015 (Table 12-31).

Table 12‑29 Transmission facility outage request summary by congestion: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)

Planned Duration (Days)

Congestion Expected

No Congestion Expected Total

Percent Congestion

ExpectedCongestion

ExpectedNo Congestion

Expected Total

Percent Congestion

Expected<=5 1,061 10,419 11,480 9.2% 1,110 10,347 11,457 9.7%>5 & <=30 209 1,831 2,040 10.2% 253 1,967 2,220 11.4%>30 84 679 763 11.0% 81 700 781 10.4%Total 1,354 12,929 14,283 9.5% 1,444 13,014 14,458 10.0%

Table 12‑30 Transmission facility outage requests that by received status, congestion and emergency: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)

Submission StatusCongestion


Expected TotalPercent

CongestionCongestion


Expected TotalPercent

CongestionLate Emergency 67 2,138 2,205 3.0% 94 1,947 2,041 4.6%

Non Emergency 262 4,622 4,884 5.4% 257 4,828 5,085 5.1%On Time Emergency 1 11 12 8.3% 3 9 12 25.0%

Non Emergency 1,024 6,158 7,182 14.3% 1,090 6,230 7,320 14.9%Total 1,354 12,929 14,283 9.5% 1,444 13,014 14,458 10.0%

Table 12‑31 Transmission facility outage requests that might cause congestion status summary: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)

Submission Status Cancelled CompleteIn

Process DeniedCongestion

ExpectedPercent

Complete Cancelled CompleteIn

Process DeniedCongestion

ExpectedPercent

CompleteLate Emergency 3 63 1 0 67 94.0% 10 82 1 1 94 87.2%

Non Emergency 48 184 1 29 262 70.2% 49 174 6 28 257 67.7%On Time Emergency 1 0 0 0 1 0.0% 0 3 0 0 3 100.0%

Non Emergency 223 736 1 64 1,024 71.9% 295 720 24 51 1,090 66.1%Total 275 983 3 93 1,354 72.6% 354 979 31 80 1,444 67.8%

Table 12-30 shows the outage requests summary by received status, congestion status and emergency status. In the first nine months of 2015, 71.4 percent of late requests were non-emergency outages while 5.1 percent of late non-emergency outage requests were expected to cause congestion in the first nine months of 2015.

Once PJM processes an outage request, the outage request is labelled as submitted, received, denied, approved, cancelled by company, revised, active or complete according to the processed stage of a request.58 Table 12-31 shows the detailed process status for outage requests only for the outage requests that are expected to cause congestion. All process status categories except cancelled, complete or denied are in the In Process category in Table 12-31. Table 12-31 shows that 67.7 percent of late, non-emergency, outage requests

which were expected to cause congestion were approved and completed and 5.5 (80 out of 1,444) percent of the outage requests which were expected to cause congestion were denied in the first nine months of 2015.

There are clear rules defined for on time or late status for submitted outage requests in both the PJM Tariff and PJM Manuals.59 However, the outcome of the rules (on time or late) only affects the priority that PJM assigns to process the outage request. Many (67.8 percent) non-emergency,

expected to cause congestion, late transmission outages were approved and completed. The expected impact on congestion is the basis for PJM’s treatment of late outage requests. But there is no rule or clear definition of this congestion analysis in the PJM Manuals. The MMU recommends that PJM have a

58 See PJM. “Outage Information,” <http://www.pjm.com/markets-and-operations/etools/oasis/system-information/outage-info.aspx> (November 1, 2015).

59 OATT Attachment K Appendix § 1.9.2 (Outage Scheduling)

Section 12 Planning


clear definition of the congestion analysis required for transmission outage requests in Manual 3.

Rescheduling Transmission Facility Outage RequestsA TO can reschedule or cancel an outage after initial submission. Table 12-32 is a summary of all the outage requests planned for the first nine months of 2014 and 2015 which were approved and then cancelled or revised by TOs at least once. In the first nine months of 2015, 2.6 percent of transmission outage requests were approved by PJM and then revised by the TOs, and 12.8 percent of the transmission outages were approved by PJM and subsequently cancelled by the TOs.

Table 12‑32 Rescheduled transmission outage request summary: January through September of 2014 and 2015

2014 (Jan ‑ Sep) 2015 (Jan ‑ Sep)

DaysOutage

RequestsApproved and

Revised

Percent Approved and

RevisedApproved and

Cancelled


CancelledOutage

RequestsApproved and

Revised


RevisedApproved and

Cancelled


Cancelled<=5 11,480 363 3.2% 1,629 14.2% 11,457 284 2.5% 1,629 14.2%>5 & <=30 2,040 85 4.2% 145 7.1% 2,220 70 3.2% 162 7.3%>30 763 29 3.8% 39 5.1% 781 28 3.6% 55 7.0%Total 14,283 477 3.3% 1,813 12.7% 14,458 382 2.6% 1,846 12.8%

All late rescheduled outages are reevaluated by PJM. An on time transmission outage ticket with duration of five days or less with an on time status can retain its on time status if the outage is rescheduled within the original scheduled month.60 This rule allows a TO to move an outage to an earlier date than originally requested within the same month with very little notice.

An on time transmission outage ticket with duration exceeding five days can retain its on time status if the outage is moved to a future month, and the revision is submitted by the first of the month prior to the month in which new proposed outage will occur.61 This rescheduling rule is much less strict than the rule that applies to the first submission of outage requests with similar duration. When first submitted, the outage request planned to last 60 PJM. “Manual 3: Transmission Outages,” Revision 46 (December 1, 2014), p. 63.61 PJM. “Manual 3: Transmission Outages,” Revision: 46 (December 1, 2014), p. 64.

longer than five days needs to be submitted the first of the month six months prior to the month in which the outage was expected to occur.

The MMU recommends that PJM reevaluate all transmission outage tickets as if they were new requests when an outage is rescheduled and apply the standard rules for late submissions to any such outages.

Long Duration Transmission Facility Outage RequestsPJM has rules (Table 12-26) to define that a transmission outage request is on time or late based on the planned outage duration. The rule has stricter submission requirement for transmission outage requests planned for longer than 30 days. In order to avoid the stricter submission requirement, some

transmission owners broke the duration of outage requests longer than 30 days into shorter segments for the same equipment and submitted one request for each segment. Table 12-33 shows that there were 9,097 transmission equipment planned outages in the first nine months of 2015, of which 714 were planned outages longer than 30 days without breaking into shorter periods, and 118 were planned outages longer than

30 days that were divided into separate shorter periods. There were 8,957 transmission equipment planned outages in the first nine months of 2014, of which 685 were planned outages longer than 30 days without breaking into shorter periods, and 112 were planned outages longer than 30 days that were divided into separate shorter periods.



Table 12‑33 Transmission outage request summary: January through September of 2014 and 2015

2014 2015

DurationDividing into

Shorter PeriodsNumber of

Outages PercentNumber of

Outages Percent> 30 Days No 685 7.6% 714 7.8%

Yes 112 1.3% 118 1.3%<= 30 Days 8,160 91.1% 8,265 90.9%Total 8,957 100.0% 9,097 100.0%

Table 12-34 is a summary of transmission equipment with scheduled outages longer than 30 days when combining all the sequential outage requests related to the equipment. For the equipment with scheduled outages in the first nine months of 2015, 4.2 percent were longer than 30 days when combined all the outages related to the equipment during one month time span, 11.0 percent during two months span, 15.3 percent during three months span, and 69.5 percent during four months or longer. For the equipment with scheduled outages in the first nine months of 2014, 3.6 percent were longer than 30 days when combined all the outages related to the equipment during one month time span, 15.2 percent during two months span, 16.1 percent during three months span, and 65.2 percent during four months or longer.

Table 12‑34 Summary of scheduled outages by breaking out into shorter period segments during a period of time span: January through September of 2014 and 2015

2014 2015Span (Months) Number of Outages Percent Number of Outages Percent1 4 3.6% 5 4.2%2 17 15.2% 13 11.0%3 18 16.1% 18 15.3%>=4 73 65.2% 82 69.5%Total 112 100.0% 118 100.0%

Transmission Facility Outage Analysis for the FTR MarketTransmission Facility Outage Analysis for the FTR Market Transmission facility outages affect the price and quantity outcomes of FTR auctions. It is

critical that outages are known with enough lead time prior to FTR auctions both so that market participants can understand market conditions and so that PJM can accurately model market conditions. Outage requests must be submitted according to rules based on planned outage duration (Table 12-26). The rules defining when an outage is late are based on the timing of FTR auctions. When an outage request is submitted late, the outage will be marked as late and may be denied if it is expected to cause congestion.

Table 12-41 shows that 43.7 percent of late outage requests with a duration of two weeks or longer but shorter than two months were completed, 1.0 percent were denied by PJM and 18.1 percent of late outage requests with a duration of two weeks or longer but shorter than two months that were approved and active in the 2015 to 2016 planning year. The table also shows that 27.3 percent of late outage requests with duration of two months or longer were completed, none of them were denied, and 43.8 percent were approved and active in the 2015 to 2016 planning year.

There are Long Term, Annual and Monthly Balance of Planning Period auctions in the FTR market. When modeling transmission outages in the annual ARR allocation and FTR auction, PJM does not consider outages with planned duration shorter than two weeks, does consider some outages with planned duration longer than two weeks but shorter than two months, and does consider all outages with planned duration longer than or equal to two months. PJM posts an FTR outage list to the FTR web page usually at least one week before the auction bidding opening day.62

Table 12-35 shows that 85.5 (8,979 out of 10,476) percent of the outage requests for outages expected to occur during the planning period 2015 to 2016 had a planned duration of less than two weeks and that 38.8 percent of all outage requests for the planning period were submitted late according to outage submission rules.

62 PJM “Annual ARR Allocation and FTR Auction Transmission Outage Modeling,” <http://www.pjm.com/~/media/markets-ops/ftr/annual-ftr-auction/2015-2016/2015-2016-annual-outage-modeling.ashx>

Section 12 Planning


Table 12‑35 Transmission facility outage requests by received status: Planning period 2015 to 2016Planned Duration On Time Late Total Percent Late<2 weeks 5,451 3,528 8,979 39.3%>=2 weeks & <2 months 796 414 1,210 34.2%>=2 months 157 121 278 43.5%Total 6,404 4,063 10,467 38.8%

Table 12-36 shows that 89.9 (17,633 out of 19,605) percent of the outage requests for outages expected to occur during the planning period 2014 to 2015 had a planned duration of less than two weeks and that 47.7 percent of all outage requests for the planning period were submitted late according to outage submission rules.

Table 12‑36 Transmission facility outage requests by received status: Planning period 2014 to 2015Planned Duration On Time Late Total Percent Late<2 weeks 9,291 8,342 17,633 47.3%>=2 weeks & <2 months 805 820 1,625 50.5%>=2 months 155 192 347 55.3%Total 10,251 9,354 19,605 47.7%

Once received, PJM processes outage requests in the following priority order: emergency transmission outage request, transmission outage requests submitted On Time, and transmission submitted Late. If two outage requests submitted by different transmission owners are expected to occur during the same period, the outage submitted first is processed first by PJM. If a request has an emergency flag, it has the highest priority and will be approved even if submitted past its deadline after PJM determines that the outage does not result in Emergency Procedures.63 Table 12-37 shows outage requests summary by emergency status. Of all outage requests submitted late in the 2015 to 2016 planning year, 73.7 percent were for non-emergency outages.

63 PJM. “Manual 3: Transmission Outages,” Revision: 47A (July 1, 2015), p. 67 and p.68.

Table 12‑37 Transmission facility outage requests by received status and emergency: Planning period 2015 to 2016

On Time Late

Planned Duration EmergencyNon

EmergencyPercent Non

Emergency EmergencyNon


Emergency<2 weeks 11 5,440 99.8% 990 2,538 71.9%>=2 weeks & <2 months 1 795 99.9% 61 353 85.3%>=2 months 1 156 99.4% 16 105 86.8%Total 13 6,391 99.8% 1,067 2,996 73.7%

Table 12-38 shows outage requests summary by emergency status. Of all outage requests submitted late in the 2014 to 2015 planning year, 72.7 percent were for non-emergency outages.

Table 12‑38 Transmission facility outage requests by received status and emergency: Planning period 2014 to 2015

On Time Late

Planned Duration EmergencyNon




Emergency<2 weeks 13 9,278 99.9% 2,362 5,980 71.7%>=2 weeks & <2 months 0 805 100.0% 155 665 81.1%>=2 months 0 155 100.0% 35 157 81.8%Total 13 10,238 99.9% 2,552 6,802 72.7%

PJM analyzes expected congestion for both on time and late outage requests. A late outage request may be denied or cancelled if it is expected to cause congestion. Table 12-39 shows a summary of requests by expected congestion and received status. Overall, 5.2 percent of all tickets submitted late in the 2015 to 2016 planning year were requests that might cause congestion.



Table 12‑39 Transmission facility outage requests by submission status and congestion: Planning period 2015 to 2016

On Time Late

Planned DurationCongestion

Expected

No Congestion

Expected

Percent Congestion

ExpectedCongestion

Expected

No Congestion

Expected

Percent Congestion

Expected<2 weeks 756 4,695 13.9% 183 3,345 5.2%>=2 weeks & <2 months 128 668 16.1% 24 390 5.8%>=2 months 33 124 21.0% 3 118 2.5%Total 917 5,487 14.3% 210 3,853 5.2%

Table 12-40 shows a summary of requests by expected congestion and received status. Overall, 5.3 percent of all tickets submitted late in the 2014 to 2015 planning year were requests that might cause congestion.

Table 12‑40 Transmission facility outage requests by submission status and congestion: Planning period 2014 to 2015

On Time Late

Planned DurationCongestion

Expected

No Congestion

Expected

Percent Congestion

ExpectedCongestion

Expected

No Congestion

Expected

Percent Congestion

Expected<2 weeks 1,332 7,959 14.3% 445 7,897 5.3%>=2 weeks & <2 months 160 645 19.9% 43 777 5.2%>=2 months 32 123 20.6% 6 186 3.1%Total 1,524 8,727 14.9% 494 8,860 5.3%

Table 12-41 shows that 43.7 percent of late outage requests with a duration of two weeks or longer but shorter than two months were completed and 18.1 percent were approved and active in the 2015 to 2016 planning year. It also shows that that 27.3 percent of late outage requests with a duration of two months or longer were completed and 43.8 percent were approved and active in the 2015 to 2016 planning period.

Table 12‑41 Transmission facility outage requests by received status and processed status: Planning period 2015 to 2016Planned Duration Processed Status On Time Percent Late Percent<2 weeks In Progress 2,086 38.3% 320 9.1%

Denied 46 0.8% 25 0.7%Approved 114 2.1% 62 1.8%Cancelled by Company 1,133 20.8% 424 12.0%Revised 17 0.3% 1 0.0%Active 72 1.3% 59 1.7%Completed 1,983 36.4% 2,637 74.7%

Total Submission 5,451 100.0% 3,528 100.0%>=2 weeks & <2 months In Progress 439 55.2% 109 26.3%

Denied 0 0.0% 4 1.0%Approved 12 1.5% 7 1.7%Cancelled by Company 143 18.0% 35 8.5%Revised 14 1.8% 3 0.7%Active 86 10.8% 75 18.1%Completed 102 12.8% 181 43.7%

Total Submission 796 100.0% 414 100.0%>=2 months In Progress 60 38.2% 23 19.0%

Denied 0 0.0% 0 0.0%Approved 1 0.6% 1 0.8%Cancelled by Company 28 17.8% 11 9.1%Revised 2 1.3% 0 0.0%Active 59 37.6% 53 43.8%Completed 7 4.5% 33 27.3%

Total Submission 157 100.0% 121 100.0%

Table 12-42 shows that 86.3 percent of late outage requests with a duration of two weeks or longer but shorter than two months were completed and that 86.5 percent of late outage requests with a duration of two months or longer were completed in the 2014 to 2015 planning period.

Section 12 Planning


Table 12‑42 Transmission facility outage requests by received status and processed status: Planning period 2014 to 2015Planned Duration Processed Status On Time Percent Late Percent<2 weeks In Process 22 0.2% 149 1.8%

Denied 105 1.1% 97 1.2%Cancelled by Company 2,759 29.7% 1,200 14.4%Completed 6,405 68.9% 6,896 82.7%

Total 9,291 100.0% 8,342 100.0%>=2 weeks & <2 months In Process 1 0.1% 8 1.0%

Denied 0 0.0% 4 0.5%Cancelled by Company 194 24.1% 100 12.2%Completed 610 75.8% 708 86.3%

Total 805 100.0% 820 100.0%>=2 months In Process 0 0.0% 7 3.6%

Denied 0 0.0% 0 0.0%Cancelled by Company 38 24.5% 19 9.9%Completed 117 75.5% 166 86.5%

Total 155 100.0% 192 100.0%

Table 12-43 shows that there were 441 outage requests with a duration of two weeks or longer but shorter than two months submitted late, of which 23 were non-emergency and expected to cause congestion in the 2015 to 2016 planning year. Of the 23 such requests, 11 were approved and completed and four were approved and active. For the outages planned for two months or longer, there were 278 total outages, of which 121 requests were late. Of the late requests, three outages that were non-emergency and expected to cause congestion were all approved and completed and one were approved and active.



Table 12‑43 Transmission facility outage requests by received status, processed status, emergency and congestion: Planning period 2015 to 2016On Time Late

EmergencyNon


EmergencyEmergency Congestion Expected

Congestion Expected

Congestion Expected

Congestion Expected

Planned Duration Processed Status Yes No Yes No Total Yes No Yes No Total<2 weeks In Progress 0 2 255 1,829 2,086 0 39 20 261 320

Denied 0 0 25 21 46 0 7 9 9 25 Approved 0 0 10 104 114 0 1 3 58 62 Cancelled by Company 0 1 151 981 1,133 4 64 25 331 424 Revised 0 0 4 13 17 0 0 0 1 1 Active 0 0 12 60 72 0 9 1 49 59 Completed 3 5 296 1,679 1,983 44 822 77 1,694 2,637

Total Submission 3 8 753 4,687 5,451 48 942 135 2,403 3,528 >=2 weeks & <2 months In Progress 0 0 63 376 439 0 6 7 96 109

Denied 0 0 0 0 0 0 0 0 4 4 Approved 0 0 1 11 12 0 0 1 6 7 Cancelled by Company 0 1 14 128 143 0 0 0 35 35 Revised 0 0 4 10 14 0 0 0 3 3 Active 0 0 21 65 86 1 7 4 63 75 Completed 0 0 25 77 102 0 47 11 123 181

Total Submission 0 1 128 667 796 1 60 23 330 414 >=2 months In Progress 0 0 10 50 60 0 1 1 21 23

Denied 0 0 0 0 0 0 0 0 0 0 Approved 0 0 0 1 1 0 0 0 1 1 Cancelled by Company 0 0 1 27 28 0 1 0 10 11 Revised 0 0 0 2 2 0 0 0 0 0 Active 0 1 21 37 59 0 9 1 43 53 Completed 0 0 1 6 7 0 5 1 27 33

Total Submission 0 1 33 123 157 0 16 3 102 121

Table 12-44 shows that there were 820 outage requests with a duration of two weeks or longer but shorter than two months submitted late, of which 40 were non-emergency and expected to cause congestion in the 2014 to 2015 planning year. Of the 40 such requests, 33 were approved and completed. For the outages planned for two months or longer, there are 347 total outages, of which 192 requests were late. Of the late request, six outages that were non-emergency and expected to cause congestion were all approved and completed.

Section 12 Planning


Table 12‑44 Transmission facility outage requests by received status, processed status, emergency and congestion: Planning period 2014 to 2015

On Time Late

EmergencyNon


EmergencyEmergency Congestion

ExpectedCongestion

ExpectedCongestion

ExpectedCongestion

ExpectedPlanned Duration Processed Status Yes No Yes No Total Yes No Yes No Total<2 weeks In Progress 0 0 2 20 22 0 70 3 76 149

Denied 0 0 70 35 105 1 12 39 45 97 Cancelled by Company 1 1 362 2,395 2,759 9 135 74 982 1,200 Completed 0 11 897 5,497 6,405 96 2,039 223 4,538 6,896

Total Submission 1 12 1,331 7,947 9,291 106 2,256 339 5,641 8,342 >=2 weeks & <2 months In Progress 0 0 1 0 1 0 3 0 5 8

Denied 0 0 0 0 0 0 1 2 1 4 Cancelled by Company 0 0 30 164 194 0 5 5 90 100 Completed 0 0 129 481 610 3 143 33 529 708

Total Submission 0 0 160 645 805 3 152 40 625 820 >=2 months In Progress 0 0 0 0 0 0 1 0 6 7

Denied 0 0 0 0 0 0 0 0 0 0 Cancelled by Company 0 0 3 35 38 0 1 0 18 19 Completed 0 0 29 88 117 0 33 6 127 166

Total Submission 0 0 32 123 155 0 35 6 151 192

Table 12‑45 Transmission facility outage requests by received status and bidding opening date: Planning period 2015 to 2016

On Time Late

Planned DurationBefore Bidding Opening Date

After Bidding Opening Date

Percent After

Before Bidding Opening Date


Percent After

<2 weeks 1,313 4,138 75.9% 65 3,463 98.2%>=2 weeks & <2 months 558 238 29.9% 62 352 85.0%>=2 months 143 14 8.9% 25 96 79.3%Total 2,014 4,390 68.6% 152 3,911 96.3%

If an outage request were submitted after the Annual FTR Auction bidding opening date, the outage would not be considered in the FTR model. If an outage were submitted on time according to the transmission outage rules, it may not be modeled in the FTR model if it is submitted after the Annual FTR Auction bidding opening date. Table 12-45 shows that 68.6 percent of outage requests labelled on time according to rules were submitted after the annual FTR bidding opening date in the 2015 to 2016 planning year.

Table 12-46 shows that 84.0 percent of outage requests labelled on time according to rules were submitted after the annual FTR bidding opening date.



Table 12‑46 Transmission facility outage requests by received status and bidding opening date: Planning period 2014 to 2015

On Time Late

Planned DurationBefore Bidding Opening Date


Percent After

Before Bidding Opening Date


Percent After

<2 weeks 1,040 8,251 88.8% 78 8,264 99.1%>=2 weeks & <2 months 475 330 41.0% 77 743 90.6%>=2 months 127 28 18.1% 18 174 90.6%Total 1,642 8,609 84.0% 173 9,181 98.2%

Table 12-47 shows that 71.2 percent of late outage requests which were submitted after the Annual FTR Auction bidding opening date were approved and complete in the 2015 to 2016 planning.

Table 12‑47 Late transmission facility outage requests that are submitted after annual bidding opening date: Planning period 2015 to 2016Planned Duration Completed Outages Total Percent<2 weeks 2,598 3,463 75.0%>=2 weeks & <2 months 156 352 44.3%>=2 months 31 96 32.3%Total 2,785 3,911 71.2%

Table 12-48 shows that 83.2 percent of late outage requests which were submitted after the Annual FTR Auction bidding opening date were approved and complete in the 2014 to 2015 planning year.

Table 12‑48 Late transmission facility outage requests that are submitted after annual bidding opening date: Planning period 2014 to 2015Planned Duration Completed Outages Total Percent<2 weeks 6,838 8,264 82.7%>=2 weeks & <2 months 648 743 87.2%>=2 months 150 174 86.2%Total 7,636 9,181 83.2%

Thus, although the definition of late outages was developed in order to prevent outages for the planning period being submitted after the Annual FTR Auction bidding opening date, the rules have not worked to prevent

this since the rule has no direct connection to the annual FTR auction opening date. The MMU recommends that PJM redesign the rule so the late outage requests submitted after the FTR Auction bidding opening date will not be approved by PJM.

Transmission Facility Outage Analysis in the Day-Ahead MarketTransmission facility outages also affect the energy market. Just as with the FTR market, it is critical that outages that affect the operating day

are known prior to the submission of offers in the Day-Ahead Energy Market both so that market participants can understand market conditions and so that PJM can accurately model market conditions.

There may be more than one instance for each outage request due to the change of the processed status. PJM maintains the history of outage requests including all the processed status changes and all the starting or ending date changes. For example, if an outage request were submitted, received, approved and completed, the four occurrences, termed instances, of the outage request will be stored in the database. In the day-ahead market transmission outage analysis, all instances of the outages planned in the first nine months of 2014 and 2015 are included. Table 12-49 shows that 13.5 percent of non-emergency outage request instances were submitted late for the day-ahead market and were expected to cause congestion in the first nine months of 2015.

Table 12‑49 Transmission facility outage request instance summary by congestion and emergency: January through September of 2015

For Day‑ahead MarketSubmission Status

Congestion Expected


Percent Congestion

Late Emergency 250 2,975 3,225 7.8%Non Emergency 1,820 11,685 13,505 13.5%

On Time Emergency 611 9,201 9,812 6.2%Non Emergency 11,246 65,419 76,665 14.7%Total 13,927 89,280 103,207 13.5%

Section 12 Planning


Table 12-50 shows that 14.1 percent of non-emergency outage request instances were submitted late for the day-ahead market and were expected to cause congestion in the first nine months of 2014.

Table 12‑50 Transmission facility outage request instance summary by congestion and emergency: January through September of 2014

For Day‑ahead MarketSubmission Status

Congestion Expected


Percent Congestion

Late Emergency 183 3,398 3,581 5.1%Non Emergency 1,934 11,789 13,723 14.1%

On Time Emergency 464 11,104 11,568 4.0%Non Emergency 10,103 63,326 73,429 13.8%Total 12,684 89,617 102,301 12.4%

Table 12‑51 Transmission facility outage request instance status summary by congestion and emergency: January through September of 2015

Late For Day‑ahead Market On Time For Day‑ahead MarketEmergency Non Emergency Emergency Non EmergencyCongestion

ExpectedCongestion

ExpectedCongestion

ExpectedCongestion

ExpectedProcessed Status Yes No Yes No Total Yes No Yes No TotalSubmitted 18 741 42 517 1,318 104 1,263 1,665 11,788 14,820 Cancelled by Company 9 34 63 564 670 7 122 436 3,253 3,818 Revised 7 91 36 233 367 78 3,152 2,094 10,690 16,014

Total 34 866 141 1,314 2,355 189 4,537 4,195 25,731 34,652 Other 216 2,109 1,679 10,371 14,375 422 4,664 7,051 39,688 51,825 Total 250 2,975 1,820 11,685 16,730 611 9,201 11,246 65,419 86,477

Table 12‑52 Transmission facility outage request instance status summary by congestion and emergency: January through September of 2014

Late For Day‑ahead Market On Time For Day‑ahead MarketEmergency Non Emergency Emergency Non EmergencyCongestion

ExpectedCongestion

ExpectedCongestion

ExpectedCongestion

ExpectedProcessed Status Yes No Yes No Total Yes No Yes No TotalSubmitted 13 867 49 511 1,440 75 1,312 1,535 11,007 13,929 Cancelled by Company 2 35 61 514 612 13 118 329 2,721 3,181 Revised 7 148 38 245 438 83 4,427 1,739 10,214 16,463

Total 22 1,050 148 1,270 2,490 171 5,857 3,603 23,942 33,573 Other 161 2,348 1,786 10,519 14,814 293 5,247 6,500 39,384 51,424 Total 183 3,398 1,934 11,789 17,304 464 11,104 10,103 63,326 84,997

Table 12-51 shows that there were 16,730 late instances related to outage requests which were expected to occur in the first nine months of 2015, of which 2,355 (18.2 percent) had the status submitted, cancelled by company or revised and 141 (0.8 percent) non-emergency instances had the status submitted, cancelled by company or revised and were expected to cause congestion.

Table 12-52 shows that there were 17,304 late instances related to outage requests which were expected to occur in the first nine months of 2014, of which 2,490 (14.4 percent) had the status submitted, cancelled by company or revised and 148 (0.9 percent) non-emergency instances had the status submitted, cancelled by company or revised and were expected to cause congestion.

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